Dual integrated psa for simultaneous power plant emission control and enhanced hydrocarbon recovery

ABSTRACT

Systems and methods are provided for combined cycle power generation and enhanced hydrocarbon production where emission gases during power generation are separated by adsorption and applied to facilitate extraction of hydrocarbons from a reservoir. A power generation plant passes exhaust gas to a first swing adsorption reactor. The first swing adsorption reactor adsorbs the CO 2  from the exhaust gas. An adsorption cycle of the first swing adsorption reactor is variable. An injection well injects the CO 2  adsorbed by the first swing adsorption reactor in a hydrocarbon reservoir. A production well that is in communication with the injection well produces a mixture of hydrocarbons and CO 2 . A second swing adsorption reactor purifies the produced hydrocarbons by adsorbing the produced CO 2  from the production well. 
     The purified hydrocarbons are fed back to the power generation plant where combustion occurs and power is generated.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Application Ser.No. 62/256,341 filed on Nov. 17, 2015, herein incorporated by referencein its entirety.

FIELD

In various aspects, the invention is related to low emission powerproduction with separation and/or capture of resulting emissions.Further, the invention is related to application of the components ofthe separation and/or capture in hydrocarbon production wells.

BACKGROUND

Capture of gases emitted from power plants is an area of increasinginterest. Power plants based on the combustion of petroleum productsgenerate carbon dioxide as a by-product of the reaction. Historicallythis carbon dioxide has been released into the atmosphere aftercombustion. However, it is becoming increasingly desirable to identifyways to find alternative uses for the carbon dioxide generated duringcombustion.

Combined cycle power plants provide an efficient way to generateelectricity from the burning of petroleum products or other carbon-basedfuels. Combined cycle power plants can leverage an initial combustionreaction to power multiple turbines for generation of electricity,leading to more efficient power generation. However, conventionalmethods for capturing carbon dioxide tend to reduce the efficiency ofelectricity generation, due to the additional energy required to captureand/or sequester the carbon dioxide.

At the same time, existing natural and industrial sources of inert gasescannot meet the growing worldwide demand of CO₂ and N₂ used for EnhancedOil Recovery (EOR) and Enhanced Gas Recovery (EGR) at hydrocarbonproduction wells. In addition, it is becoming imperative to capture andsequester greenhouse gases such as CO₂ from power generation plants.

In instances of tertiary recovery of mature oilfields, natural sourcesof CO₂ are produced and distributed, where available, in a pipelinenetwork that provides the CO₂ to oilfields where CO₂ EOR recoverymethods will extend the production lifetime of the oilfield. However,this type of naturally sourced CO₂ and associated pipelineinfrastructure only exists in certain regions of the U.S., specificallyin the Permian Basin and in the Gulf Coast region of the U.S. In manyother major oil producing areas, neither naturally sourced CO₂ nor a CO₂pipeline network exists. As a result, the demand for CO₂ to be used forEOR exceeds the available supply of naturally sourced CO₂. Therefore,new technology is required for generating CO₂ at low cost.

Furthermore, in light of the emergent need to reduce the emission of CO₂from power plants, there is an acute need for new technology thatenables capture of CO₂ from power plants at low cost. There is a needfor technology that would simultaneously enable the low cost capture ofCO₂ for EOR and provide N₂ for EGR or EOR at a reduced cost incomparison with the conventional technologies (e.g., N₂ generation usinga cryogenic air separation plant).

SUMMARY

Systems and methods are provided for combined cycle power generation andenhanced hydrocarbon production where emission gases during powergeneration may be separated by adsorption and applied to facilitateextraction of hydrocarbons from a reservoir.

In one embodiment, a method for optimizing hydrocarbon productioncomprises: passing recycle exhaust gas from a power generation plant toa first swing adsorption reactor, wherein the exhaust gas includes CO₂and N₂; adsorbing the CO₂ from the exhaust gas on a first adsorbentmaterial of the first swing adsorption reactor, wherein an adsorptioncycle of the first swing adsorption reactor is variable; injecting theCO₂ adsorbed by the first swing adsorption reactor in a hydrocarbonreservoir by using an injection well; producing a mixture ofhydrocarbons and CO₂ by using a production well, which is incommunication with the injection well; and purifying the producedhydrocarbons by adsorbing the produced CO₂ from the production well on asecond adsorbent material of a second swing adsorption reactor.

A N₂ stream unadsorbed by the first swing adsorption reactor may exitthe first swing adsorption reactor at a pressure that is substantiallythe same as a pressure of the exhaust gas from the power generationplant. The method for optimizing hydrocarbon production may furthercomprise recovering a N₂ stream unadsorbed by the first swing adsorptionreactor, or it may further comprise purging the second swing adsorptionreactor with a stream of N₂ unadsorbed by the first swing adsorptionreactor. The method for optimizing hydrocarbon production may includefeeding the purified hydrocarbons back into the power generation plantand generating power.

The adsorption cycle of the first swing adsorption reactor may be variedto adjust composition of adsorbed CO₂ based on a composition ofhydrocarbons in the hydrocarbon reservoir. The composition of thehydrocarbons in the hydrocarbon reservoir may vary with age of thereservoir. At least one of the first swing adsorption reactor and thesecond swing adsorption reactor may be a high-temperature reactor.Further, the hydrocarbons may include CH₄.

The method for optimizing hydrocarbon production may include purging thefirst swing adsorption reactor with at least one of steam, a stream ofN₂, a stream of CO₂, and a stream of CH₄ and purging the second swingadsorption reactor with at least one of a stream of CO₂ and a stream ofCH₄ flowing from the production well.

In another embodiment, a method for optimizing power generationcomprises: passing recycle exhaust gas from a power generation plant toa first swing adsorption reactor, wherein the exhaust gas includes CO₂and N₂; adsorbing the CO₂ from the exhaust gas on a first adsorbentmaterial of the first swing adsorption reactor, wherein an adsorptioncycle of the first swing adsorption reactor is variable; injecting theCO₂ adsorbed by the first swing adsorption reactor in a hydrocarbonreservoir by using an injection well; producing a mixture ofhydrocarbons and CO₂ by using a production well, which is incommunication with the injection well; and purifying the producedhydrocarbons by adsorbing the produced CO₂ from the production well on asecond adsorbent material of a second swing adsorption reactor.

A N₂ stream unadsorbed by the first swing adsorption reactor may exitthe first swing adsorption reactor at a pressure that is substantiallythe same as a pressure of the exhaust gas from the power generationplant. The method for optimizing power generation may further compriserecovering a N₂ stream unadsorbed by the first swing adsorption reactor,or it may further comprise purging the second swing adsorption reactorwith a stream of N₂ unadsorbed by the first swing adsorption reactor.The method for optimizing power generation may include feeding thepurified hydrocarbons back into the power generation plant andgenerating power.

The adsorption cycle of the first swing adsorption reactor may be variedto adjust composition of adsorbed CO₂ based on a composition ofhydrocarbons in the hydrocarbon reservoir. The composition of thehydrocarbons in the hydrocarbon reservoir may vary with age of thereservoir. At least one of the first swing adsorption reactor and thesecond swing adsorption reactor may be a high-temperature reactor.Further, the hydrocarbons may include CH₄.

The method for optimizing power generation may include purging the firstswing adsorption reactor with at least one of steam, a stream of N₂, astream of CO₂, and a stream of CH₄ and purging the second swingadsorption reactor with at least one of a stream of CO₂ and a stream ofCH₄ flowing from the production well.

One example of the present invention is system for optimizinghydrocarbon production, comprising: a power generation plant thatproduces recycle exhaust gas, wherein the exhaust gas includes CO₂ andN₂; a first swing adsorption reactor, wherein the power generation plantpasses the exhaust gas to the first swing adsorption reactor, whereinthe first swing adsorption reactor adsorbs the CO₂ from the exhaust gason a first adsorbent material of the first swing adsorption reactor, andwherein an adsorption cycle of the first swing adsorption reactor isvariable; an injection well that injects the CO₂ adsorbed by the firstswing adsorption reactor in a hydrocarbon reservoir; a production wellthat is in communication with the injection well and that produces amixture of hydrocarbons and CO₂; and a second swing adsorption reactorthat purifies the produced hydrocarbons by adsorbing the produced CO₂from the production well on a second adsorbent material of the secondswing adsorption reactor.

The adsorption cycle of the first swing adsorption reactor may be variedto adjust composition of adsorbed CO₂ based on a composition ofhydrocarbons in the hydrocarbon reservoir. The purified hydrocarbons maybe fed back into the power generation plant to generate power.

Another example of the present invention is a system for optimizingpower generation, comprising: a power generation plant that producesrecycle exhaust gas, wherein the exhaust gas includes CO₂ and N₂; afirst swing adsorption reactor, wherein the power generation plantpasses the exhaust gas to the first swing adsorption reactor, whereinthe first swing adsorption reactor adsorbs the CO₂ from the exhaust gason a first adsorbent material of the first swing adsorption reactor, andwherein an adsorption cycle of the first swing adsorption reactor isvariable; an injection well that injects the CO₂ adsorbed by the firstswing adsorption reactor in a hydrocarbon reservoir; a production wellthat is in communication with the injection well and that produces amixture of hydrocarbons and CO₂; and a second swing adsorption reactorthat purifies the produced hydrocarbons by adsorbing the produced CO₂from the production well on a second adsorbent material of the secondswing adsorption reactor.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 schematically shows an example of a combined cycle system forgenerating electricity based on combustion of a carbon-based fuel.

FIG. 2 schematically shows a configuration for a pressure swingadsorption process.

FIG. 3 shows a graph of CO₂ purity versus steam purge content forExample 4.

FIG. 4 pictorially shows the cycle setup of a 3-vessel sorptivearrangement without interconnection between vessels.

FIG. 5 pictorially shows the cycle setup of a 4-vessel sorptivearrangement without interconnection between vessels.

FIG. 6 pictorially shows the cycle setup of a 4-vessel sorptivearrangement with some level of interconnection between vessels.

FIG. 7 schematically shows an example of a dual PSA for integratedemissions control and hydrocarbon production.

FIG. 8 schematically shows an example of a dual PSA for integratedemissions control and hydrocarbon production with N₂ purge of one of thePSAs.

DETAILED DESCRIPTION OF THE EMBODIMENTS

In various aspects, systems and methods are provided for powergeneration using turbines while reducing and/or mitigating emissionsduring power generation. In a combined cycle generation system, the fluegas from a combustion reaction for a gas turbine can also be used topower a steam turbine. The flue gas can then be recycled for use as partof the input to the gas turbine. A portion of the recycled exhaust gascan be effectively separated to generate a high purity carbon dioxidestream, while reducing and/or minimizing the energy required for theseparation, and without needing to reduce the temperature of the fluegas. This can allow another (e.g., the remaining) portion of therecycled exhaust gas, which can typically be composed of a majority ofnitrogen, to be used to generate additional electricity, e.g., withouthaving to adjust the pressure and/or temperature of the recycled exhaustgas to accommodate the conditions required for the carbon dioxideseparation process. Thus, improved energy recovery can be realized fromthe combined cycle system, while also generating relatively high puritystreams of carbon dioxide and nitrogen.

A variety of system configuration and processing conditions cancontribute to power generation with low emissions that can also beeffectively separated and/or captured for further use. For example, theinput gas flow for the combustor to the gas turbine can be selected tohave a desirable composition, e.g., a roughly stoichiometric ratio offuel to oxygen. Having a roughly stoichiometric ratio of fuel to oxygencan reduce the amount of unreacted oxygen present in the gas outputafter combustion. This can facilitate separation of the other combustionproducts, as well as potentially reducing/eliminating the production ofNO_(x) species. More generally, a roughly stoichiometric combustionreaction with a desirable feed can result in an exhaust primarilycomposed of CO₂, N₂, and H₂O.

Another example of a system configuration and/or process condition thatcan contribute to power generation with low emission that can beeffectively separated and/or captured can include using recycled exhaustgas as part of the input gas flow. The gas flow exiting the combustionprocess can advantageously be used to power a gas turbine. Afterpowering the gas turbine, this gas flow corresponds to an exhaust gas.This exhaust gas can be used in a combined cycle configuration power asteam turbine by using a heat exchanger to extract heat from the exhaustgas. This exhaust gas can then be recycled, after removal of water, foruse as part of the input gas flow. The exhaust gas can advantageouslyhave an elevated volume percentage of CO₂ relative to ambient air, whichcan also assist in selecting the CO₂ content of the input gas flow tothe combustion reaction. Controlling the amount of CO₂ in the combustionproducts can be beneficial for enhancing the energy output captured fromthe combustion reaction.

Recycling all of the exhaust gas can allow for all of the carbon in theexhaust to be maintained in a single stream until the stream can bediverted to a carbon capture process. Typically, though, less than allof the recycled exhaust gas may be needed to provide additional gas forthe input gas flow to combustion. As a result, any excess exhaust gascan be diverted, e.g., for separation into high purity CO₂ and N₂ gasstreams. A convenient location in the process to perform this diversioncan be after the recycled exhaust gas has been modified to achieve thetemperature and pressure desired for the input gas flow to combustion.At this point, it can be desirable to perform the separation of CO₂ andN₂ while reducing/minimizing the amount of energy lost due totemperature/pressure reductions. For example, typical solvent methodsfor separating CO₂ and N₂ require a reduction in the temperature of therecycled exhaust gas. For such conventional solvent methods, in order topreserve as much energy in the N₂ stream as possible, heat exchangerscan be used to transfer heat from the recycled exhaust gas to theseparated N₂ stream.

In some aspects, the separation of CO₂ and N₂ can be performed by usinga pressure swing adsorption (PSA) process to separate the CO₂ and N₂ atthe temperature and pressure of the input gas flow to the combustionreaction. Using pressure swing adsorption to perform the separation canallow for recovery, for example, of at least about 60% (such as at leastabout 65%, at least about 70%, at least about 75%, at least about 80%,at least about 85%, at least about 90%, at least about 95%, at leastabout 97%, at least about 98%, at least about 99%, at least about 99.3%,or at least about 99.5%) of the CO₂ in the recycled exhaust gas, e.g.,while also generating an N₂ stream with at least about 90% purity (suchas at least about 93% purity, at least about 95% purity, at least about97% purity, at least about 98% purity, or at least about 99% purity)and/or a CO₂ stream with at least about 80% purity (such as at leastabout 85% purity, at least about 90% purity, at least about 95% purity,at least about 97% purity, at least about 98% purity, at least about 99%purity, at least about 99.3% purity, or at least about 99.5% purity).

In various aspects, the operating conditions for a PSA reactor can beselected to facilitate the power generation process while stilleffectively capturing the exhaust gases. Using a relatively hightemperature PSA can preserve the energy content of the N₂ portion of therecycled exhaust gas, so that the N₂ gas stream can be used to power anadditional turbine for electricity generation. By contrast, aconventional separation method for CO₂ separation such as solventseparation can typically require adjustment of the temperature and/orpressure of the stream to facilitate the separation. Thus, instead ofrequiring energy to modify the recycled exhaust prior to treating theexhaust gases, use of a PSA reactor can allow the capture process to beadjusted to match the operating conditions for power generation.

The high temperature PSA can also be performed using a process cycleavoiding the need for high temperature steam and/or another energyintensive purge gas. This can allow high purity CO₂ to be recoveredwhile reducing/minimizing the amount of energy lost to capture of theexhaust gases.

Combined Cycle Process for Power Generation with Low Emissions

In various aspects, systems and methods are provided for generatingpower while controlling and/or capturing the emissions produced duringpower generation. One goal of power generation is to use input feeds(such as fuels) as efficiently as possible, so that power generation canbe increased/optimized for a given amount of fuel and/or of equipment.Based on the conditions for effective power generation, a goal forcontrol/capture of emissions can be to provide effective capture ofemissions while reducing/minimizing the changes to the conditions forpower generation.

As used herein, the term “stoichiometric combustion” refers to acombustion reaction having a volume of reactants comprising a fuel andan oxidizer and a volume of products formed by combusting the reactants,where substantially the entire volume of the reactants is used to formthe products. As used herein, the term “substantially stoichiometriccombustion” refers to a combustion reaction having a molar ratio ofcombustion fuel to oxygen ranging from plus to minus about 10%, e.g.,from about plus to minus about 5%, of the oxygen required for astoichiometric ratio. For example, the stoichiometric ratio of fuel tooxygen for methane is 1:2 (CH₄+2O₂⇄CO₂+2H₂O), whereas propane shouldhave a stoichiometric ratio of fuel to oxygen of 1:5. Another way ofmeasuring substantially stoichiometric combustion can be as a ratio ofoxygen supplied to oxygen required for stoichiometric combustion, e.g.,from about 0.9:1 to about 1.1:1 or from about 0.95:1 to about 1.05:1.

In some aspects, the processes described herein can be used to produceultra low emission electric power and CO₂ for EOR, enhanced hydrocarbonrecovery (EHR), and/or sequestration/capture applications; in suchcases, the process conditions for EOR/EHR may be similar tosequestration/capture application or may be slightly different. In oneor more aspects, a mixture of oxygen-enriched gas (e.g., enriched air)and fuel can be stoichiometrically or substantially stoichiometricallycombusted and simultaneously mixed with a stream of recycled exhaustgas. The stream of recycled exhaust gas, generally including products ofcombustion such as CO₂, can be used as a diluent to control, adjust,and/or otherwise moderate the temperature of combustion and the exhaustthat enters the succeeding expander. As a result of using oxygenenrichment, the recycled exhaust gas can have an increased CO₂ content,thereby allowing the expander to operate at even higher expansion ratiosfor the same inlet and discharge temperatures, thereby producingsignificantly increased power.

Combustion in commercial gas turbines at stoichiometric conditions orsubstantially stoichiometric conditions (e.g., “slightly rich”combustion) can prove advantageous to eliminate the cost of excessoxygen removal. By cooling the exhaust and condensing the water out ofthe cooled exhaust stream, a relatively high content CO₂ exhaust streamcan be produced. While a portion of the recycled exhaust gas can beutilized for temperature moderation in a closed Brayton cycle, aremaining purge stream can be used for EOR and/or enhanced hydrocarbonrecovery applications and/or electric power can be produced with littleor no sulfur oxides (SO_(x)), nitrogen oxides (NO_(x)), and/or CO₂ beingemitted to the atmosphere. The result of this process can include theproduction of power in three separate cycles and the manufacturing ofadditional CO₂. In some aspects, performing stoichiometric combustioncan allow for generation of an exhaust stream consisting substantiallyof CO₂, H₂O, and N₂. An exhaust stream consisting substantially of CO₂,H₂O, and N₂ is defined as an exhaust stream that contains about 5 mol %or less of other gas molecules, e.g., about 2.5 mol % or less or about 1mol % or less.

FIG. 1 depicts a schematic of an illustrative integrated system 100 forpower generation and CO₂ recovery using a combined-cycle arrangement,according to one or more embodiments. In at least one embodiment, thepower generation system 100 can include a gas turbine system 102characterized as a power-producing, closed Brayton cycle. The gasturbine system 102 can have a first or main compressor 104 coupled to anexpander 106 via a shaft 108. The shaft 108 can be any mechanical,electrical, and/or other power coupling, thereby allowing a portion ofthe mechanical energy generated by the expander 106 to drive the maincompressor 104. In at least one embodiment, the gas turbine system 102can be a standard gas turbine, where the main compressor 104 andexpander 106 form the compressor and expander ends, respectively. Inother embodiments, however, the main compressor 104 and expander 106 canbe individualized components in the system 102.

The gas turbine system 102 can also include a combustion chamber 110configured to combust a fuel introduced via line 112 mixed with anoxidant introduced via line 114. In one or more embodiments, the fuel inline 112 can include any suitable hydrocarbon gas or liquid, such asnatural gas, methane, ethane, naphtha, butane, propane, syngas, diesel,kerosene, aviation fuel, coal derived fuel, bio-fuel, oxygenatedhydrocarbon feedstock, or any combinations thereof. The oxidant via line114 can be derived from a second or inlet compressor 118 fluidly coupledto the combustion chamber 110 and adapted to compress a feed oxidantintroduced via line 120. In one or more embodiments, the feed oxidant inline 120 can include atmospheric air, enriched air, or combinationsthereof. When the oxidant in line 114 includes a mixture of atmosphericair and enriched air, the enriched air can be compressed by the inletcompressor 118 before and/or after being mixed with the atmospheric air.The enriched air can have an overall oxygen concentration of at leastabout 30 vol %, e.g., at least about 35 vol %, at least about 40 vol %,at least about 45 vol %, at least about 50 vol %, from about 30 vol % toabout 70 vol %, from about 30 vol % to about 65 vol %, from about 30 vol% to about 60 vol %, from about 30 vol % to about 55 vol %, from about30 vol % to about 50 vol %, from about 35 vol % to about 70 vol %, fromabout 35 vol % to about 65 vol %, from about 35 vol % to about 60 vol %,from about 35 vol % to about 55 vol %, from about 35 vol % to about 50vol %, from about 40 vol % to about 70 vol %, from about 40 vol % toabout 65 vol %, from about 40 vol % to about 60 vol %, from about 40 vol% to about 55 vol %, from about 40 vol % to about 50 vol %, from about45 vol % to about 70 vol %, from about 45 vol % to about 65 vol %, fromabout 45 vol % to about 60 vol %, from about 45 vol % to about 55 vol %,from about 45 vol % to about 50 vol %, from about 50 vol % to about 70vol %, from about 50 vol % to about 65 vol %, or from about 50 vol % toabout 60 vol %.

The enriched air can be derived from any one or more of several sources,including implementing various technologies upstream of the inletcompressor 118 to produce the enriched air. For example, the enrichedair can be derived from such separation technologies as membraneseparation, pressure swing adsorption, temperature swing adsorption,nitrogen plant-byproduct streams, and/or combinations thereof. Theenriched air can additionally or alternately be derived from an airseparation unit (ASU), such as a cryogenic ASU, for producing nitrogenfor pressure maintenance or other purposes. The reject stream from theASU can be rich in oxygen, e.g., having an overall oxygen content fromabout 50 vol % to about 70 vol %. This reject stream can be used as atleast a portion of the enriched air and subsequently diluted, if needed,with unprocessed atmospheric air to obtain the desired oxygenconcentration for the application.

As will be described in more detail below, the combustion chamber 110can also receive a compressed recycle exhaust gas in line 144, includingan exhaust gas recirculation primarily having CO₂ and nitrogencomponents. The compressed recycle exhaust gas in line 144 can bederived from the main compressor 104 and adapted to help facilitate astoichiometric or substantially stoichiometric combustion of thecompressed oxidant in line 114 and fuel in line 112 by moderating thetemperature of the combustion products. As can be appreciated,recirculating the exhaust gas can serve to increase the CO₂concentration in the exhaust gas.

An exhaust gas in line 116 directed to the inlet of the expander 106 canbe generated as a product of combustion of the fuel in line 112 and thecompressed oxidant in line 114, in the presence of the compressedrecycle exhaust gas in line 144. In at least one embodiment, the fuel inline 112 can be primarily natural gas, thereby generating a discharge orexhaust gas via line 116 that can include volumetric portions ofvaporized water, CO₂, nitrogen, nitrogen oxides (NO_(x)), and sulfuroxides (SO_(x)). In some embodiments, a small portion of unburned fuelin line 112 or other compounds can also be present in the exhaust gas inline 116 due to combustion equilibrium limitations. As the exhaust gasin line 116 expands through the expander 106, it can generate mechanicalpower to drive the main compressor 104, an electrical generator, and/orother facilities, and can also produce a gaseous exhaust in line 122having a heightened CO₂ content resulting from the influx of thecompressed recycle exhaust gas in line 144. In some implementations, theexpander 106 may be adapted to produce additional mechanical power thatmay be used for other purposes.

Additionally or alternately, the power generation system 100 can includean exhaust gas recirculation (EGR) system 124, which can include a heatrecovery steam generator (HRSG) 126, or similar device, fluidly coupledto a steam gas turbine 128. In at least one embodiment, the combinationof the HRSG 126 and the steam gas turbine 128 can be characterized as apower-producing closed Rankine cycle. In combination with the gasturbine system 102, the HRSG 126 and the steam gas turbine 128 can formpart of a combined-cycle power generating plant, such as a natural gascombined-cycle (NGCC) plant. The gaseous exhaust in line 122 can beintroduced to the HRSG 126 in order to generate steam via line 130 and acooled exhaust gas in line 132. Additionally or alternately, the steamin line 130 can be sent to the steam gas turbine 128 to generateadditional electrical power.

The cooled exhaust gas in line 132 can be sent to a first cooling unit134 adapted to cool the cooled exhaust gas in line 132 and generate acooled recycle gas stream 140. The first cooling unit 134 can include,for example, one or more contact coolers, trim coolers, evaporativecooling unit, or any combination thereof. The first cooling unit 134 canadditionally or alternately be adapted to remove a portion of anycondensed water from the cooled exhaust gas in line 132 via a waterdropout stream 138. In at least one embodiment, the water dropout stream138 may be routed to the HRSG 126 via line 141 to provide a water sourcefor the generation of additional steam in line 130 therein. Additionallyor alternately, the water recovered via the water dropout stream 138 canbe used for other downstream applications, such as supplementary heatexchanging processes.

In most embodiments, the cooled recycle gas stream 140 can be directedto a boost compressor 142. Cooling the cooled exhaust gas in line 132 inthe first cooling unit 134 can reduce the power required to compress thecooled recycle gas stream 140 in the boost compressor 142. As opposed toa conventional fan or blower system, the boost compressor 142 can beconfigured to compress, and thus increase, the overall density of thecooled recycle gas stream 140, thereby directing a pressurized recyclegas in line 145 downstream, where the pressurized recycle gas in line145 can thus exhibit an increased mass flow rate for the same volumetricflow. This can prove advantageous, since the main compressor 104 can bevolume-flow limited, and directing more mass flow through the maincompressor 104 can result in higher discharge pressures, therebytranslating into higher pressure ratios across the expander 106. Higherpressure ratios generated across the expander 106 can allow for higherinlet temperatures and, therefore, an increase in expander 106 powerand/or efficiency. As can be appreciated, this may prove advantageous,since the CO₂-rich exhaust gas in line 116 can generally maintain ahigher specific heat capacity.

Since the suction pressure of the main compressor 104 can typically be afunction of its suction temperature, a cooler suction temperature cangenerally demand less power to operate the main compressor 104 for thesame mass flow. Consequently, the pressurized recycle gas in line 145can optionally be directed to a second cooling unit 136, e.g., which caninclude one or more direct contact coolers, trim coolers, evaporativecooling units, or any combination thereof. In at least one embodiment,the second cooling unit 136 can serve as an aftercooler adapted toremove at least a portion of the heat of compression generated by theboost compressor 142 on the pressurized recycle gas in line 145. Thesecond cooling unit 136 can additionally or alternately extractadditional condensed water via a water dropout stream 143. In some suchembodiments, the water dropout streams 138,143 can converge into stream141 and may or may not be routed to the HRSG 126 to generate additionalsteam via line 130 therein. While only first and second cooling units134,136 are depicted herein, any desired number of cooling units can beemployed to suit a variety of applications, without departing from thescope of the disclosure.

The main compressor 104 can be configured to receive and compress thepressurized recycle gas in line 145 to a pressure nominally at or abovethe pressure of the combustion chamber 110, thereby generating thecompressed recycle exhaust gas in line 144. As can be appreciated,cooling the pressurized recycle gas in line 145 in the second coolingunit 136 after compression in the boost compressor 142 can allow for anincreased volumetric mass flow of exhaust gas into the main compressor104. Consequently, this can reduce the amount of power required tocompress the pressurized recycle gas in line 145 to a predeterminedpressure.

In many embodiments, a purge stream 146 can be recovered from thecompressed recycle exhaust gas in line 144 and subsequently treated in aCO₂ separator 148 to capture CO₂ at an elevated pressure via line 150.Preferably, the CO₂ separator can be a pressure swing adsorption unit,as described in further detail below. The separated CO₂ in line 150 canbe used for sales, used in another processes requiring CO₂, and/orfurther compressed and injected into a terrestrial reservoir for EOR,EHR, sequestration, or another purpose. Because of the stoichiometric orsubstantially stoichiometric combustion of the fuel in line 112 combinedwith a boosted pressure from the boost compressor 142, the CO₂ partialpressure in the purge stream 146 can be much higher than in conventionalgas turbine exhausts.

A residual stream 151, essentially depleted of CO₂ and consistingprimarily of nitrogen, can additionally or alternately be derived fromthe CO₂ separator 148. In some embodiments, the residual stream 151 canbe introduced to a gas expander 152 to provide power and an expandeddepressurized gas, or exhaust gas, via line 156. The expander 152 canbe, for example, a power-producing nitrogen expander. As depicted, thegas expander 152 can be optionally coupled to the inlet compressor 118through a common shaft 154 or other mechanical, electrical, or otherpower coupling, thereby allowing a portion of the power generated by thegas expander 152 to drive the inlet compressor 118. However, duringstartup of the system 100 and/or during normal operation, when the gasexpander 152 is unable to supply all the required power to operate theinlet compressor 118, at least one motor 158, such as an electric motor,can be used synergistically with the gas expander 152. For instance, themotor 158 can be sensibly sized such that, during normal operation ofthe system 100, the motor 158 can be configured to supply the powershort-fall from the gas expander 152. In other embodiments, however, thegas expander 152 can be used to provide power to other applications, andnot directly coupled to the inlet compressor 118. For example, there maybe a substantial mismatch between the power generated by the expander152 and the requirements of the compressor 118. In such cases, theexpander 152 could be adapted to drive a smaller (or larger) compressor(not shown) that may demand less (or more) power.

An expanded depressurized gas in line 156, primarily consisting of drynitrogen gas, can be discharged from the gas expander 152. In at leastone embodiment, the combination of the gas expander 152, inletcompressor 118, and CO₂ separator 148 can be characterized as an openBrayton cycle, and/or a third power-producing component of the powergeneration system 100. Conventional systems and methods of expanding thenitrogen gas in the residual stream 151, and variations thereof, arebelieved to be known in the art and are thus not discussed herein.

Additionally or alternately, gas expander 152 can be replaced and/orcomplemented with a downstream compressor 158. At least a portion (andup to all) of the residual stream 151 can be compressed in a downstreamcompressor to generate a compressed exhaust gas via line 160, which canbe suitable for injection into a reservoir for pressure maintenanceapplications. In applications where methane gas is typically reinjectedinto hydrocarbon wells to maintain well pressures, compressing theresidual stream 151 may prove advantageous. For example, the pressurizednitrogen gas in line 160 can instead be injected into the hydrocarbonwells, and any residual methane gas can be sold or otherwise used asfuel in related applications, such as in line 112.

By using enriched air as the compressed oxidant in line 114 andpressurizing the exhaust gas in the boost compressor 142, the powergeneration system 100 can achieve higher concentrations of CO₂ in theexhaust gas, thereby allowing for more effective CO₂ separation andcapture. Embodiments disclosed herein, for example, can effectivelyincrease the concentration of CO₂ in the exhaust gas in line 116 to CO₂concentrations ranging from about 10 vol % to about 20 vol %. To achievesuch CO₂ concentrations, the combustion chamber 110 can be adapted tostoichiometrically or substantially stoichiometrically combust anincoming mixture of fuel in line 112 and compressed oxidant in line 114,where the compressed oxidant in line 114 can include a stream having anoxygen content greater than about 21 vol %, e.g., enriched air, such ashaving an overall oxygen concentration of about 30 vol %, about 35 vol%, about 40 vol %, about 45 vol %, or about 50 vol %.

In order to moderate the temperature of the stoichiometric combustionand meet expander 106 inlet temperature and component coolingrequirements, a portion of the exhaust gas with increased CO₂ contentderived from the compressed recycle exhaust gas in line 144 can beinjected into the combustion chamber 110 as a diluent. Thus, embodimentsof the disclosure can essentially eliminate excess oxygen from theexhaust gas in line 116, while advantageously increasing its CO₂concentration, e.g., up to about 20 vol % or optionally higher. As such,the gaseous exhaust in line 122 can have less than about 3.0 vol %oxygen, for example less than about 1.0 vol % oxygen, less than about0.1 vol % oxygen, or less than about 0.01 vol % oxygen.

At least one benefit of having an increased CO₂ concentration can bethat the expander 106 can be operated at an even higher expansion ratiofor the same inlet and discharge temperatures, and can thereby produceincreased power. This can be due to the higher heat capacity of CO₂relative to nitrogen found in ambient air. In one or more aspects, theexpansion ratio of the expander 106 can be increased from about 17.0 toabout 20.0, corresponding to about 10 vol % and about 20 vol % CO₂recycle streams, respectively. For example, enriched air having about 35vol % oxygen can be used in order to achieve the about 20 vol % in theCO₂ recycle stream.

Additional or alternate benefits of having an increased CO₂concentration in the recycle gas can include, but are not limited to, anincreased concentration of CO₂ in the extracted purge stream 146 usedfor CO₂ separation. Because of its increased CO₂ concentration, thepurge stream 146 need not be as large in order to extract the requiredamounts of CO₂. For example, the equipment handling extraction for CO₂separation can be smaller, including its piping, heat exchangers,valves, absorber towers, etc. Moreover, increased concentrations of CO₂can improve the performance of CO₂ removal technology, including usinglow-energy separation processes, such as employing less energy-intensivesolvents that would otherwise be untenable. Consequently, capitalexpenditures for capturing CO₂ can be dramatically lowered.

An example of operation of the system 100 will now be discussed. Asshould be appreciated, specific temperatures and pressuresachieved/experienced in the various components of any of the embodimentsdisclosed herein can change depending on, among other factors, thepurity of the oxidant used and/or the specific makes and/or models ofexpanders, compressors, coolers, etc. Accordingly, it should beappreciated that the particular data described herein is forillustrative purposes only and should not be construed as the onlyinterpretation thereof. In an embodiment, the inlet compressor 118 canprovide compressed oxidant in line 114 at a pressure between about 280psia (about 1.9 MPa) and about 300 psia (about 2.1 MPa). Alsocontemplated herein, however, is aeroderivative gas turbine technology,which can produce and consume pressures of up to about 750 psia (about5.2 MPa) and higher.

The main compressor 104 can be configured to recycle and compressrecycled exhaust gas into the compressed recycle exhaust gas in line 144at a pressure nominally at or above the combustion chamber 110 pressure,and to use a portion of that recycled exhaust gas as a diluent in thecombustion chamber 110. Because amounts of diluent needed in thecombustion chamber 110 can depend on the purity of the oxidant used forstoichiometric combustion or the particular model/design of expander106, a ring of thermocouples and/or oxygen sensors (not shown) can bedisposed on the outlet of the expander 106. In operation, thethermocouples and/or sensors can be adapted to regulate and determinethe volume of exhaust gas required as diluent needed to cool theproducts of combustion to the required expander inlet temperature, andalso to provide feedback to regulate the amount of oxidant beinginjected into the combustion chamber 110. Thus, in response to the heatrequirements detected by the thermocouples and/or the oxygen levelsdetected by the oxygen sensors, the volumetric mass flow of compressedrecycle exhaust gas in line 144 and compressed oxidant in line 114 canbe manipulated up or down to track the demand.

In at least one embodiment, a pressure drop of about 12-13 psi (about83-90 kPa) can be experienced across the combustion chamber 110 duringstoichiometric or substantially stoichiometric combustion. Combustion ofthe fuel in line 112 and the compressed oxidant in line 114 can generatetemperatures between about 2000° F. (about 1093° C.) and about 3000° F.(about 1649° C.) and pressures ranging from about 250 psia (about 1.7MPa) to about 300 psia (about 2.1 MPa). As described above, because ofthe increased mass flow and higher specific heat capacity of theCO₂-rich exhaust gas derived from the compressed recycle exhaust gas inline 144, higher pressure ratios can be achieved across the expander106, thereby allowing for higher inlet temperatures and increasedexpander 106 power.

The gaseous exhaust in line 122 exiting the expander 106 can exhibitpressures at or near ambient, e.g., about 13-17 psia (about 90-120 kPa).The temperature of the gaseous exhaust in line 122 can be from about1225° F. (about 663° C.) to about 1275° F. (about 691° C.) beforepassing through the HRSG 126 to generate steam in line 130 and a cooledexhaust gas in line 132. In one or more embodiments, the cooling unit134 can reduce the temperature of the cooled exhaust gas in line 132,thereby generating the cooled recycle gas stream 140 having atemperature between about 32° F. (about 0° C.) and about 120° F. (about49° C.). As can be appreciated, such temperatures can fluctuate, e.g.,depending on wet bulb temperatures during specific seasons in specificlocations around the globe.

According to one or more embodiments, the boost compressor 142 can beconfigured to elevate the pressure of the cooled recycle gas stream 140to a pressure ranging from about 17 psia (about 120 kPa) to about 21psia (about 140 kPa). As a result, the main compressor 104 caneventually receive and compress a recycled exhaust with a higher densityand increased mass flow, thereby allowing for a substantially higherdischarge pressure while maintaining the same or similar pressure ratio.In order to further increase the density and mass flow of the recycleexhaust gas, the pressurized recycle gas in line 145 discharged from theboost compressor 142 can then be further cooled in the optional secondcooling unit 136, which can, in some embodiments, be configured toreduce the pressurized recycle gas temperature in line 145 to about 105°F. (about 41° C.) before being directed to the main compressor 104.

Additionally or alternately, the temperature of the compressed recycleexhaust gas in line 144 discharged from the main compressor 104, andconsequently the temperature of the purge stream 146, can be about 800°F. (about 427° C.), with a pressure of around 280 psia (about 1.9 MPa).The addition of the boost compressor 142 and the stoichiometriccombustion of enriched air can increase the CO₂ purge pressure in thepurge stream 146, which can lead to improved solvent treatingperformance in the CO₂ separator 148 due to the higher CO₂ partialpressure.

Swing Adsorber Processes—Overview

Pressure swing adsorption (PSA) relies on swinging or cycling pressureover a bed of adsorbent through a range of values. In PSA processes, agaseous mixture is conducted under pressure for a period of time over afirst bed of a solid sorbent that is selective, or relatively selective,for one or more components, usually regarded as a contaminant, to beremoved from the gaseous mixture. For example, a feed can be introducedinto a PSA apparatus at a feed pressure. At the feed pressure, one ormore of the components (gases) in the feed can be selectively (orrelatively selectively) (ad)sorbed, while one or more other components(gases) can pass through with lower or minimal adsorption. A component(gas) that is selectively (ad)sorbed can be referred to as a “heavy”component of a feed, while a gas that is not selectively (ad)sorbed canbe referred to as a “light” component of a feed. For convenience, areference to the “heavy” component of the feed can refer to allcomponents (gases) that are selectively (ad)sorbed, unless otherwisespecified. Similarly, a reference to the “light” component can refer toall components (gases) that are not selectively (ad)sorbed, unlessotherwise specified. After a period of time, the feed flow into the PSAapparatus can be stopped. The feed flow can be stopped based on apredetermined schedule, based on detection of breakthrough of one ormore heavy components, based on (ad)sorption of the heavy component(s)corresponding to at least a threshold percentage of the total capacityof the (ad)sorbent, or based on any other convenient criteria. Thepressure in the reactor can then be reduced to a desorption pressurethat can allow the selectively (ad)sorbed component(s) (gas(es)) to bereleased from the (ad)sorbent. Optionally, one or more purge gases canbe used prior to, during, and/or after the reduction in pressure tofacilitate release of the selectively (ad)sorbed component(s) (gas(es)).Depending on its nature, a full PSA cycle can optionally be performed ata roughly constant temperature. As PSA is usually enabled by at leastadsorption and usually occurs on gaseous components, the terms“adsorption”/“adsorbent” and “gas(es)” are used as descriptors in theinstant specification and claims, without intending to be limiting inscope, even though “absorption”/“absorbent”/“sorbent”/“sorption” and“component(s)” may be more generally applicable.

Multiple beds can be used to enable a complete cycle, where typicallyevery bed sequentially goes through the same cycle. When a first PSAreactor satisfies a condition, such as the adsorbent in the reactorbecoming sufficiently saturated, the feed flow can be switched to asecond reactor. The first PSA reactor can then be regenerated by havingthe adsorbed gases released. To allow for a continuous feed flow, asufficient number of PSA reactors and/or adsorbent beds can be used sothat the first PSA reactor is finished regenerating prior to at leastone other PSA reactor satisfying the condition for switching reactors.

Swing Adsorber Processes—Process Cycle

In various aspects, a PSA reactor can be used for performing aseparation on a stream containing CO₂ and N₂. An example of such astream can include the exhaust stream from a combustion reaction forproviding power for a gas turbine. Preferably, the exhaust stream can bethe exhaust from a combustion reaction performed with a substantiallystoichiometric composition with regard to the amount of oxygen and fuel.Prior to use as a feed for separation by PSA, the exhaust stream canundergo further processing, such as condensation to remove water,combustion to remove excess fuel, adsorption for removal of NO_(x)species, and/or other types of processing to remove components differentfrom CO₂ and N₂. In some aspects, the portion of the exhaust stream usedas the feed for the PSA reactor can have a water content of less thanabout 1.0 vol %, such as less than about 0.5 vol %. Additionally oralternately, the portion of the exhaust stream used as the feed for thePSA reactor can have an O₂ content of less than about 3.0 vol %, such asless than about 1.0 vol % or less than about 0.5 vol %. Furtheradditionally or alternately, the feed into the PSA reactor can besubstantially composed of CO₂ and N₂, where components of the input gasfeed different from CO₂ and N₂ are present in an amount of about 1.0 vol% or less each, such as less than about 0.5 vol % each. Still furtheradditionally or alternately, in a feed substantially composed of CO₂ andN₂, the combined vol % of components other than CO₂ and N₂ can be about2.0 vol % or less, such as about 1.0 vol % or less or 0.5 vol % or less.

To perform a separation, a portion of the recycled exhaust stream can beintroduced into a PSA reactor, such as a purge stream from the exhauststream recycle loop. The portion of the recycled exhaust stream can bewithdrawn from the exhaust recycle system at a location after thetemperature and pressure of the recycled exhaust stream have beenmodified (and/or after desired temperature and pressure have beenobtained) for use as part of the input gas flow to the combustionreaction. At such point in the recycle system, the exhaust stream canhave a temperature from about 300° C. to about 600° C., e.g., from about300° C. to about 550° C., from about 300° C. to about 500° C., fromabout 300° C. to about 450° C., from about 300° C. to about 400° C.,from about 350° C. to about 600° C., from about 350° C. to about 550°C., from about 350° C. to about 500° C., from about 350° C. to about450° C., from about 400° C. to about 600° C., from about 400° C. toabout 550° C., from about 400° C. to about 500° C., from about 425° C.to about 600° C., from about 425° C. to about 550° C., from about 425°C. to about 500° C., from about 425° C. to about 460° C., from about450° C. to about 600° C., from about 450° C. to about 550° C., fromabout 500° C. to about 600° C. Additionally or alternately, thetemperature can be at least about 325° C., e.g., at least about 350° C.,at least about 400° C., at least about 425° C., or at least about 440°C. Further additionally or alternately, the temperature can be about575° C. or less, about 550° C. or less, about 500° C. or less, about475° C. or less, about 460° C. or less, or about 440° C. or less. Stillfurther additionally or alternately, the pressure of the recycledexhaust stream can be at least about 10 bara (about 1.0 MPa), e.g., atleast about 15 bara (about 1.5 MPa), at least about 20 bara (about 2.0MPa), at least about 25 bara (about 2.5 MPa), or at least about 30 bara(about 3.0 MPa). Yet further additionally or alternately, the pressurecan be about 60 bara (6.0 MPa) or less, e.g., about 50 bara (about 5.0MPa) or less, about 40 bara (about 4.0 MPa) or less, about 35 bara(about 3.5 MPa) or less, about 30 bara (about 3.0 MPa) or less, about 25bara (about 2.5 MPa) or less, or about 22.5 bara (about 2.25 MPa) orless. In some alternative aspects, other locations for withdrawing theportion of the recycled exhaust stream can be selected, so long as thewithdrawn portion has similar temperature and pressure values.

In some aspects, the recycled exhaust stream can be introduced into thePSA reactor at a separation temperature and a separation pressure thatcan correspond to the temperature and pressure of the recycle stream.However, some variation in temperature and/or pressure may occur betweenwithdrawal of the portion of the recycled exhaust stream from therecycle system and introduction of the recycled exhaust stream into thePSA reactor. For example, the separation temperature for the portion ofthe recycled exhaust stream introduced into the PSA reactor can differfrom the temperature in the recycle system by about 20° C. or less,e.g., by about 15° C. or less or by about 10° C. or less. It is notedthat, although having the same temperature for the separationtemperature and the temperature in the recycle stream (i.e., adifference of approximately 0° C.) is included within the enumerateddifferences, in some rare embodiments the temperature differences canoptionally exclude 0° C. Additionally or alternately, the separationpressure for the portion of the recycled exhaust stream introduced intothe PSA reactor can differ from the pressure in the recycle system byabout 5 bar (0.5 MPa) or less, e.g., about 2 bara (0.2 MPa) or less,about 1 bara (about 0.1 MPa) or less, or about 0.5 bar (about 50 kPa) orless.

When the exhaust stream is introduced into the PSA reactor, the N₂ inthe exhaust stream corresponds to a “light” component while the CO₂corresponds to a “heavy” component. Thus, the N₂ can primarily passthrough the reactor while the CO₂ can be selectively adsorbed within thereactor. The adsorption of CO₂ from the feed can result in a product N₂stream. The feed can be passed through the PSA reactor until one or morepre-defined criteria is satisfied for switching the feed to another PSAreactor or otherwise stopping the flow of feed gas. Any convenientpre-defined criteria can be used. For example, the feed can be passedthrough the reactor for a specified time period. Additionally oralternately, the feed can be passed into the reactor until abreakthrough amount of CO₂ is detected in the product N₂ stream. Furtheradditionally or alternately, the feed can be passed into the reactoruntil the amount of CO₂ that has entered the reactor is approximatelyequal to a threshold value of the adsorbent capacity of the reactor. Insuch a situation, for example, the feed can be passed into the reactoruntil the amount of CO₂ that has entered the reactor is equal to atleast about 75% of the adsorbent capacity of the adsorbent material inthe reactor, such as at least about 80%, at least about 85%, or at leastabout 90%. A typical PSA cycle can involve introducing feed into thereactor for about 30 seconds to about 300 seconds, e.g., for about 60seconds to about 120 seconds.

The product N₂ stream can have a purity of at least about 85 vol %,e.g., at least about 88 vol %, at least about 90 vol %, at least about92 vol %, at least about 93 vol %, at least about 94 vol %, at leastabout 95 vol %, at least about 96 vol %, at least about 97 vol %, or atleast about 98 vol %. After optional removal of water, the product N₂stream can have a purity of at least about 90 vol %, e.g., at leastabout 95 vol %, at least about 97 vol %, at least about 98 vol %, or atleast 99 vol %. The pressure of the N₂ stream can be at least about 90%,e.g., at least about 95%, of the pressure of the recycled exhaust usedas the input to the PSA reactor. Additionally or alternately, thepressure of the N₂ stream can differ from the separation pressure byless than about 0.5 bar (about 50 kPa), e.g., less than about 0.3 bar(about 30 kPa) or less than about 0.1 bar (about 10 kPa). Furtheradditionally or alternately, the separation temperature for the portionof the recycled exhaust stream introduced into the PSA reactor candiffer from the temperature of the N₂ product stream by about 20° C. orless, e.g., by about 15° C. or less or by about 10° C. or less. It isnoted that, although having the same temperature for the separationtemperature and the temperature in the recycle stream (i.e., adifference of approximately 0° C.) is included within the enumerateddifferences, in some rare embodiments the temperature differences canoptionally exclude 0° C. Additionally or alternately, the temperature ofthe N₂ product stream can be at least the temperature of the PSA reactor(the adsorption temperature) during the adsorption portion of theseparation cycle.

After the feed is stopped, the pressure in the PSA reactor can bereduced, e.g., using one or more blow down processes. In a blow downprocess, one or both sides of a PSA reactor can be opened to allowpressure to release in the form of a blow down gas stream. The blow downgas stream can generally include a majority portion of N₂ and can alsotypically include some CO₂. The amount of adsorbed CO₂ released in theblow down process(es) can depend on the nature of the adsorbent. In someconventional PSA reactors, the blow down gas stream can be exhaustedfrom the feed input side of the reactor. Alternatively, one or more blowdown gas streams can be exhausted from the product side of the reactor.For example, one option can include having an initial blow down processexiting from the product side of the reactor followed by a second blowdown process allowing a gas stream to exit from both sides of thereactor. The blow down process(es) can reduce the pressure in thereactor to a value from about 0.9 bara (about 90 kPa) to about 3.0 bara(about 0.3 MPa), e.g., from about 1.0 bara (about 0.1 MPa) to about 3.0bara (about 0.3 MPa), from about 1.1 bara (about 110 kPa) to about 3.0bara (about 0.3 MPa), from about 1.3 bara (about 130 kPa) to about 3.0bara (about 0.3 MPa), from about 0.9 bara (about 90 kPa) to about 2.6bara (about 260 kPa), from about 1.0 bara (about 0.1 MPa) to about 2.6bara (about 260 kPa), from about 1.1 bara (about 110 kPa) to about 2.6bara (about 260 kPa), from about 1.3 bara (about 130 kPa) to about 2.6bara (about 260 kPa), from about 0.9 bara (about 90 kPa) to about 2.0bara (about 0.2 MPa), from about 1.0 bara (about 0.1 MPa) to about 2.0bara (about 0.2 MPa), from about 1.1 bara (about 110 kPa) to about 2.0bara (about 0.2 MPa), or from about 1.3 bara (about 130 kPa) to about2.0 bara (about 0.2 MPa). In many embodiments, maintaining a pressureabove atmospheric pressure in the reactor can assist with the adsorbentretaining CO₂ until a subsequent purge step when desorption is desired.In some embodiments, the length of time for the blow down processes canbe from about 30 seconds to about 120 seconds.

In some aspects, the use of multiple blow down steps can be desirablefor creating blow down streams that are easier to subsequently process.For example, during adsorption of CO₂ from an exhaust gas, a profile cantypically develop in the reactor, with a higher content of non-adsorbedCO₂ near the back (input) end of the reactor and a lower content of CO₂near the exit (front) end of the reactor. Based on this profile, apartial blow down from only the exit (front) end of the reactor can beused to produce a blow down output with a low CO₂ content. This initialblow down step can result in the higher CO₂ content near the back(input) end of the reactor being distributed more evenly throughout thereactor. As this occurs, it can then be more efficient to allow blowdown output streams to exit from both ends of the reactor until thedesired lower pressure can be achieved.

Preferably, a buffer gas is not introduced into the reactor during thetime between stopping the flow of exhaust gas and starting the blow downprocess step(s). It can additionally or alternately be preferred thatthe blow down process step(s) can be performed without introducing anadditional gas into the reactor. Avoiding the use of buffer gases and/oradditional gases in the blow down steps can be desirable, becauseintroduction of such gases after the flow of exhaust gas is stopped cantypically result in further loss of value into a low value stream. Forexample, the output flows generated by the blow down step(s) are, bydefinition, lower pressure output flows relative to the product N₂ flowgenerated during the separation of the exhaust gas. Thus, the N₂ in theblow down output has typically lost much of its value from a powergeneration standpoint. Prior to further use, the N₂ in the blow downoutput flow can likely need to be recompressed. Adding additional N₂after the flow of exhaust gas is stopped can typically only increase theamount of N₂ in this low value output flow. The blow down output flowcan preferably be relatively low in CO₂, as it can generally bedesirable to retain as much CO₂ as possible until the start of thesubsequent purge step(s). Any CO₂ that exits the PSA reactor as part ofa blow down stream represents additional CO₂ in a stream other than thedesired CO₂ product stream. This additional CO₂, which can typically bein low concentration, can then need to be separately handled if it isdesired to achieve as high an amount of carbon capture and recovery aspossible. Thus, adding additional CO₂ here is also not typicallydesirable. Finally, adding a third gas different from CO₂, N₂, or H₂Omay not be desirable, as introduction of such a gas can likely result inanother component requiring separation.

After the blow down process(es), one or more purge gas flows can be usedto remove the adsorbed CO₂ from the reactor. One option can includeusing a steam purge at a pressure from about 1.0 bara (about 0.1 MPa) toabout 3.0 bara (about 0.3 MPa), e.g., from about 1.1 bara (about 110kPa) to about 3.0 bara (about 0.3 MPa), from about 1.3 bara (about 130kPa) to about 3.0 bara (about 0.3 MPa), from about 1.0 bara (about 0.1MPa) to about 2.6 bara (about 260 kPa), from about 1.1 bara (about 110kPa) to about 2.6 bara (about 260 kPa), from about 1.3 bara (about 130kPa) to about 2.6 bara (about 260 kPa), from about 1.0 bara (about 0.1MPa) to about 2.0 bara (about 0.2 MPa), from about 1.1 bara (about 110kPa) to about 2.0 bara (about 0.2 MPa), or from about 1.3 bara (about130 kPa) to about 2.0 bara (about 0.2 MPa), to assist in desorbing theCO₂. An alternative option can include using a steam purge at a pressureabove 3.0 bara (0.3 MPa), e.g., of at least 4.0 bara (0.4 MPa), of atleast 5.0 bara (0.5 MPa), from above 3.0 bara (0.3 MPa) to about 20 bara(about 2 MPa), from above 3.0 bara (0.3 MPa) to about 15 bara (about 1.5MPa), from above 3.0 bara (0.3 MPa) to about 10 bara (about 1 MPa), fromabove 3.0 bara (0.3 MPa) to about 8 bara (about 0.8 MPa), from above 3.0bara (0.3 MPa) to about 6 bara (about 0.6 MPa), from above 3.0 bara (0.3MPa) to about 5 bara (about 0.5 MPa), from 4.0 bara (0.4 MPa) to about20 bara (about 2 MPa), from 4.0 bara (0.4 MPa) to about 15 bara (about1.5 MPa), from 4.0 bara (0.4 MPa) to about 10 bara (about 1 MPa), from4.0 bara (0.4 MPa) to about 8 bara (about 0.8 MPa), from 4.0 bara (0.4MPa) to about 6 bara (about 0.6 MPa), from 4.0 bara (0.4 MPa) to about 5bara (about 0.5 MPa), from 5.0 bara (0.5 MPa) to about 20 bara (about 2MPa), from 5.0 bara (0.5 MPa) to about 15 bara (about 1.5 MPa), from 5.0bara (0.5 MPa) to about 10 bara (about 1 MPa), from 5.0 bara (0.5 MPa)to about 8 bara (about 0.8 MPa), or from 5.0 bara (0.5 MPa) to about 6bara (about 0.6 MPa). The steam purge can result in a product CO₂ outputstream that can also include H₂O and a lesser amount of N₂. In someembodiments, the steam purge can last for about 25 seconds to about 60seconds. After removal of water, the product CO₂ stream can have apurity of at least about 60%, e.g., at least about 65%, at least about70%, at least about 75%, at least about 80%, at least about 85 vol %, atleast about 90 vol %, at least about 92 vol %, at least about 94 vol %,at least about 95 vol %, at least about 96%, at least about 97%, atleast about 98%, at least about 99%, at least about 99.3%, or at leastabout 99.5%. Additionally or alternately, the amount of CO₂ recoveredcan correspond to at least about 80 vol %, e.g., at least about 85 vol%, at least about 90 vol %, at least about 92 vol %, at least about 94vol %, at least about 95 vol %, at least about 96%, at least about 97%,at least about 98%, at least about 99%, at least about 99.3%, or atleast about 99.5%.

The amount of steam used in the steam purge can correspond to about 1.0moles of water or less per mole of CO₂ in the feed, e.g., about 0.9moles of water or less per mole of CO₂ in the feed, about 0.75 moles ofwater or less per mole of CO₂ in the feed, about 0.6 moles of water orless per mole of CO₂ in the feed, about 0.5 moles of water or less permole of CO₂ in the feed, or about 0.4 moles of water or less per mole ofCO₂ in the feed. Using less steam in the purge can be beneficial,because the amount of steam used can typically correspond to the amountof energy used for the CO₂ recovery. It is noted that the feed cantypically contain at least 50 mol %, and often at least 75 mol %, of N₂.Thus, a comparison of the number of moles of water per total moles ofgas (including both N₂ and CO₂) in the feed could produce still lowervalues, e.g., about 0.5 moles of water or less per mole of gas in thefeed, about 0.4 moles of water or less per mole of gas in the feed,about 0.3 moles of water or less per mole of gas in the feed, about 0.25moles of water or less per mole of gas in the feed, about 0.2 moles ofwater or less per mole of gas in the feed, about 0.15 moles of water orless per mole of gas in the feed, or about 0.1 moles of water or lessper mole of gas in the feed. In such embodiments where there is anon-zero amount of steam used in the steam purge, the molar ratio ofsteam can be at least about 0.05 moles of water or less per mole of CO₂in the feed (e.g., at least about 0.1 moles of water or less per mole ofCO₂ in the feed, at least about 0.2 moles of water or less per mole ofCO₂ in the feed, or at least about 0.3 moles of water or less per moleof CO₂ in the feed) and/or can be at least about 0.01 moles of water orless per mole of gas in the feed (e.g., at least about 0.02 moles ofwater or less per mole of gas in the feed, at least about 0.05 moles ofwater or less per mole of gas in the feed, or at least about 0.1 molesof water or less per mole of gas in the feed).

After the steam purge, a second nitrogen purge can optionally be used toremove water and any remaining CO₂ from the reactor. If the second purgeis not used, the N₂ output stream in the next cycle may have higherwater content, but otherwise the additional water is not believed tosignificantly impact the separation process. When a second nitrogenpurge is used, it can be performed for about 10 seconds to about 45seconds. After the steam purge and the optional second nitrogen purge,the reactor can then be repressurized to start the next separationcycle. The repressurization can be performed using the input feed (therecycled exhaust gas). Alternatively but preferably, a second purge,such as a second nitrogen purge, may not be performed, as such a secondpurge can represent a flow of buffer gas between the end of a purge stepand the start of the next cycle of introducing exhaust gas forseparation of N₂ and CO₂. For the reasons noted above, additional buffergas steps can typically be undesirable, as such buffer steps can tend toresult in additional volume for low value gas streams.

In an alternative embodiment, no steam is intentionally used as a purgegas in the desorption step of the PSA cycle. In such an alternativeembodiment, if a purge gas is used at all, it would not intentionallyinclude water but, for instance, could include a nitrogen purge (e.g.,which can last for about 10 seconds to about 60 seconds, for about 10seconds to about 50 seconds, for about 10 seconds to about 45 seconds,for about 15 seconds to about 60 seconds, for about 15 seconds to about50 seconds, for about 15 seconds to about 45 seconds, for about 20seconds to about 60 seconds, for about 20 seconds to about 50 seconds,for about 20 seconds to about 45 seconds, for about 25 seconds to about60 seconds, for about 25 seconds to about 50 seconds, or for about 25seconds to about 45 seconds). It should be understood that, even in suchembodiments where no steam is intentionally added, some water/steam maynevertheless be present as an impurity/contaminant in any purge streamthat is used. In such alternative embodiments, the use of nointentionally added steam can allow the CO₂ from the PSA process to beintroduced directly into CO₂ compressors, e.g., for well injection inenhanced oil recovery processes, without the need for intermediateequipment such as condensers or heat exchangers. Similar recoveriesand/or purities of CO₂ can be achieved in this alternative embodiment,though obviously water need not be removed to attain those recoveriesand/or purities in such an embodiment.

An additional/alternate way of characterizing the desire toreduce/minimize the use of buffer gases can be by characterizing thetotal gas input flows into the PSA reactor during a process cycle. Inthe process described above, a full cycle of the process can correspondto passing an initial gas flow into the reactor for separation,adsorbing CO₂ from the input gas flow, recovering an N₂ product stream,blowing down the pressure in the reactor, and purging the reactor withsteam, optionally including a second purge stream. If only a steam purgeis used, the primary input gas flows into the PSA reactor during aprocess cycle can include the input gas flow of recycled exhaust gas andthe steam purge. Preferably, these primary input flows can correspond toat least about 90 vol % of all gas flows into the PSA reactor, e.g., atleast about 95 vol %, at least about 98 vol %, or at least about 99 vol%. If a second purge of N₂ or another second purge gas is used, then theprimary input gas flows into the PSA reactor during a process cycle caninclude the input gas flow of recycled exhaust gas, the steam purge, andthe second purge. Preferably, in such an embodiment, these primary inputflows can correspond to at least about 90 vol % of all gas flows intothe PSA reactor, e.g., at least about 95 vol %, at least about 98 vol %,or at least about 99 vol %.

FIG. 2 schematically shows an example of the gas flows into and out of apressure swing adsorption unit suitable for use in separating an exhaustgas containing CO₂ and N₂. In FIG. 2, a pressure swing adsorptionreactor 210 can receive a feed 205 containing CO₂ and N₂ for separationfrom a first or back side of the reactor. An N₂ product stream 202 canemerge from a second or forward side of the reactor. After a period oftime, such as after breakthrough of the CO₂, the feed to the PSA can bestopped. One or more blow down processes can then be performed to reducethe pressure in the reactor. In FIG. 2, a forward blow down output 222is shown. Optionally, either a back blow down or both a back and aforward blow down can be used in place of a forward blow down 222. Apurge stream such as a steam purge 215 can then be introduced into theforward side of the reactor. The purge stream can assist in desorbingCO₂ from the adsorbent to produce the CO₂ product stream 212.

Though not specifically delineated in any of the Figures herein, thepurified CO₂ output of the PSA process can be used in applications torecover oil, gas, or associated hydrocarbons from surface and/orsubterranean deposits (e.g., conventional downhole oil/natural gasreservoirs, unconventional reservoirs/wells, shale oil deposits, shalegas deposits, tight gas sands, stranded gas deposits, fracking deposits,and the like). In many of these embodiments, relatively high CO₂purities may be desirable, e.g., to increase efficiency and reduce costsassociated with compressing impurities. Nevertheless, in certain ofthese embodiments, at least some part of enhanced oil/gas/hydrocarbonrecovery can efficiently utilize lower CO₂ purities (e.g., from about60% to about 85% or from about 60% to about 80%), and particularly canoffer a distinct benefit from methods according to the invention thatallow (increased) flexibility in CO₂ stream purity (e.g., a stagedflood, wherein a sequence of different purities are used). Such flexiblepurity control can be aligned with a particular deposit/reservoir thatcan age over time and/or with the quality of a particular deposit.

Swing Adsorber Processes—Reactor Configuration

Beds of adsorbent can be arranged in any convenient manner to provide aflow path for gas, including axial and/or radial flow directions. Thevessels holding the bed of adsorbent can be oriented with respect toflow direction in any convenient manner. One typical orientation for aPSA reactor can be to have a reactor where the direction of flow isaligned with the long or primary axis of the reactor. An example of thisincludes having PSA reactors in the form of vertical cylinders, wherethe input gas flow enters the cylinder through the top or bottomsurface. While this can represent a conventional configuration for a PSAreactor relative to the direction of gas flow, scaling up a process tohandle large flow volumes can pose difficulties. For example, a typicallength to diameter ratio for a PSA reactor can be about 3 to 1, such asa reactor with a length of about 10 meters and a diameter of about 3meters. Increasing the size of such a reactor can generally result in anincreasing pressure drop across the reactor, which is typically notdesirable. Thus, in order to scale up axial flow PSA reactors to handlelarge gas flows, multiple reactors can typically be used.

Additionally or alternately, a PSA reactor can be used where the long orprimary axis of the reactor can be perpendicular to the direction of gasflow. For example, a PSA reactor can include parallel plates ofadsorbent with the long axis of the parallel plates being perpendicularto the direction of gas flow. This can allow a much larger volume ofadsorbent for capturing CO₂ to be placed in a single reactor with anaxial flow orientation while reducing the distance the gas flow musttravel to cross the reactor. As a result, this type of configuration canreduce the pressure drop across a PSA reactor while still handling largevolumes of input gas flow. This can reduce the number of separatereactors required to handle a large flow.

As an example, a horizontally oriented PSA reactor can have parallelplates of adsorbent of approximately rectangular shape, e.g., with along axis of about 30 meters and a short axis of about 4 meters. In thehorizontal configuration, the input gas can be introduced to flow acrossthe short axis. This can be accomplished by introducing the input gas atseveral locations along a side of the reactor corresponding to the longaxis. Flow distributors can then be used inside the PSA reactor so thatthe input gas can be distributed along the entire length of the longaxis. For large gas flow rates, the pressure drop from distributing thefeed across the long axis of a PSA reactor can be lower than attemptingto force such a large gas flow rate through a plurality of conventionalaxial flow PSA reactors.

Swing Adsorber Processes—Adsorbent Materials

In various aspects, a swing adsorption process can be performed toseparate N₂ from CO₂ at a temperature and pressure beneficial for otheraspects of the combined power generation process. For example, therecycled exhaust gas can have a temperature from about 300° C. to about600° C. (e.g., from about 300° C. to about 550° C., from about 300° C.to about 500° C., from about 300° C. to about 450° C., from about 300°C. to about 400° C., from about 350° C. to about 600° C., from about350° C. to about 550° C., from about 350° C. to about 500° C., fromabout 350° C. to about 450° C., from about 400° C. to about 600° C.,from about 400° C. to about 550° C., from about 400° C. to about 500°C., from about 425° C. to about 600° C., from about 425° C. to about550° C., from about 425° C. to about 500° C., from about 425° C. toabout 460° C., from about 450° C. to about 600° C., from about 450° C.to about 550° C., or from about 500° C. to about 600° C.; additionallyor alternately, the temperature can be at least about 325° C., e.g., atleast about 350° C., at least about 400° C., at least about 425° C., orat least about 440° C.; further additionally or alternately, thetemperature can be about 575° C. or less, about 550° C. or less, about500° C. or less, about 475° C. or less, about 460° C. or less, or about440° C. or less) and a pressure from about 10 bara (about 1.0 MPa) toabout 60 bara (about 6.0 MPa) (e.g., a pressure of at least about 10bara (about 1.0 MPa), at least about 15 bara (about 1.5 MPa), at leastabout 20 bara (about 2.0 MPa), at least about 25 bara (about 2.5 MPa),or at least about 30 bara (about 3.0 MPa) and/or a pressure of about 60bara (6.0 MPa) or less, about 50 bara (about 5.0 MPa) or less, about 40bara (about 4.0 MPa) or less, about 35 bara (about 3.5 MPa) or less,about 30 bara (about 3.0 MPa) or less, about 25 bara (about 2.5 MPa) orless, or about 22.5 bara (about 2.25 MPa) or less).

As noted above, one goal of the separation process can be to perform theseparation under conditions compatible with the power generationprocess. Thus, it can be desirable to perform the separation atapproximately the temperature and pressure of the recycled exhaust gas.In order to accomplish a separation at the conditions of the recycledexhaust gas, the adsorbent material in the pressure swing adsorberreactor should generally be effective under such conditions.

One example of a suitable adsorbent includes a mixed metal oxideadsorbent, such as an adsorbent including a mixture of an alkali metalcarbonate and an alkaline earth metal oxide and/or a transition metaloxide. Examples of suitable alkali metal carbonates can include, but arenot limited to, a carbonate of lithium, sodium, potassium, rubidium,cesium, or a combination thereof, e.g., a carbonate of lithium, sodium,potassium, or a combination thereof. Examples of suitable alkaline earthmetal oxides can include, but are not limited to, oxides of magnesium,calcium, strontium, barium, or a combination thereof, e.g., oxides ofmagnesium and/or calcium. Some examples of suitable transition metaloxides can include, but are not limited to, oxides of lanthanide seriesmetals, such as lanthanum, and/or of transition metals that can formoxides with the metal in a +2 or +3 oxidation state (such as yttrium,iron, zinc, nickel, vanadium, zirconium, cobalt, or a combinationthereof).

In some aspects, the carbonate can be selected independently from theoxide in the mixed metal oxide. In such aspects, the carbonate caninclude, consist essentially of, or be lithium carbonate, sodiumcarbonate, potassium carbonate, rubidium carbonate, and/or cesiumcarbonate (e.g., lithium carbonate, sodium carbonate, and/or potassiumcarbonate; lithium carbonate and/or potassium carbonate; lithiumcarbonate and/or sodium carbonate; or sodium carbonate and/or potassiumcarbonate).

In aspects where the carbonate is selected independently from the oxide,the oxide can be an alkaline earth oxide, a transition metal oxide, acombination of two or more alkaline earth oxides, a combination of twoor more transition metal oxides, or a combination of oxides including atleast one alkaline earth oxide and at least one transition metal oxide.In aspects where the independently selected oxide includes one or morealkaline earth oxides, a suitable alkaline earth oxide can include,consist essentially of, or be magnesium oxide, calcium oxide, strontiumoxide, and/or barium oxide, e.g., including at least magnesium oxideand/or calcium oxide.

In aspects where the independently selected oxide includes one or moretransition metal oxides, suitable transition metals can include, consistessentially of, or be one or more transition metals that can form oxideswith the metal in a +2 or +3 oxidation state (e.g., yttrium oxide, ironoxide, zinc oxide, nickel oxide, vanadium oxide, cobalt oxide, zirconiumoxide, lanthanum oxide, other oxides of lanthanide metals, and/or acombination thereof). One preferred option includes a transition metaloxide selected from lanthanum oxide and/or zirconium oxide. Anotheroption includes a metal oxide selected from lanthanum oxide, yttriumoxide, zirconium oxide, and/or zinc oxide. Yet another option includes ametal oxide selected from nickel oxide, cobalt oxide, and/or iron oxide.Mixtures within each of these options and/or across options are alsocontemplated, such as mixtures of lanthanum oxide with zinc oxide and/orvanadium oxide; mixtures of lanthanum oxide with iron oxide, cobaltoxide, and/or nickel oxide; mixtures of zirconium oxide with yttriumoxide, zinc oxide, and/or vanadium oxide; and mixtures of zirconiumoxide with iron oxide, cobalt oxide, and/or nickel oxide.

In aspects where the independently selected oxide includes one or morealkali metal oxides and one or more transition metal oxides, suitablealkali metal oxides can include, consist essentially of, or be magnesiumoxide, calcium oxide, strontium oxide, and/or barium oxide, whilesuitable transition metals can include, consist essentially of, or betransition metals that can form oxides with the metal in a +2 or +3oxidation state, such as yttrium oxide, iron oxide, zinc oxide, nickeloxide, vanadium oxide, cobalt oxide, zirconium oxide, lanthanum oxide,and/or other lanthanide oxides. Each of these alkali metal oxides andtransition metal oxides can be independently selected individually or inany combination of multiple transition metal oxides. Examples ofmixtures can include, consist essentially of, or be a mixture of oxideswhere at least one oxide is lanthanum oxide, zirconium oxide, and/ormagnesium oxide; a mixture of oxides where the mixture includes at leasttwo of lanthanum oxide, zirconium oxide, and magnesium oxide; a mixtureof oxides where one oxide is magnesium oxide and/or calcium oxide;and/or a mixture of oxides where at least one oxide is lanthanum oxide,yttrium oxide, and/or zirconium oxide.

In some alternative aspects, a mixed metal oxide can include an alkalineearth carbonate in combination with a transition metal oxide. In suchaspects, the alkaline earth carbonate can include, consist essentiallyof, or be magnesium carbonate and/or calcium carbonate. Additionally oralternately, the alkaline earth carbonate can be present in a mixturewith an alkali metal carbonate. Examples of such carbonate mixtures caninclude, consist essentially of, or be mixtures of lithium carbonatewith magnesium carbonate, lithium carbonate with calcium carbonate,potassium carbonate with magnesium carbonate, potassium carbonate withcalcium carbonate, sodium carbonate with magnesium carbonate, and sodiumcarbonate with calcium carbonate (e.g., lithium carbonate with magnesiumcarbonate or potassium carbonate with magnesium carbonate). In suchaspects, suitable transition metals can include, consist essentially of,or be transition metals that can form oxides with the metal in a +2 or+3 oxidation state, such as yttrium oxide, iron oxide, zinc oxide,nickel oxide, vanadium oxide, cobalt oxide, zirconium oxide, lanthanumoxide, other lanthanide oxides, and/or a combination thereof. Each ofthese alkaline earth carbonates and transition metal oxides can beindependently selected individually or in any combination of multiplealkaline earth carbonates and/or multiple transition metal oxides. Forthe transition metal oxide, one preferred option can include atransition metal oxide selected from lanthanum oxide or zirconium oxide.Another option can include a metal oxide selected from lanthanum oxide,yttrium oxide, zirconium oxide, and/or zinc oxide. Yet another optioncan include a metal oxide selected from nickel oxide, cobalt oxide,and/or iron oxide. Mixtures within each of these options and/or acrossoptions are also contemplated, such as mixtures of oxides where at leastone oxide is lanthanum oxide and/or zirconium oxide; mixtures oflanthanum oxide with zinc oxide and/or vanadium oxide; mixtures oflanthanum oxide with iron oxide, cobalt oxide, and/or nickel oxide;mixtures of zirconium oxide with yttrium oxide, zinc oxide, and/orvanadium oxide; and/or mixtures of zirconium oxide with iron oxide,cobalt oxide, and/or nickel oxide.

Additional or alternative materials can include hydrotalcites.

Several examples of pressure swing adsorption are described below.

EXAMPLE 1 Performing Pressure Swing Adsorption on a Portion of RecycledExhaust

The following predictive example is based on a configuration for apressure swing adsorption reactor similar to the configuration shown inFIG. 2. In this example, a mixed-metal oxide based adsorbent is used ina plurality of PSA reactors to separate CO₂ and N₂. The separation isperformed at a temperature between about 400° C. and about 500° C. ThePSA reactors correspond to multiple horizontally aligned vessels, suchas 3 or 4 vessels. The reactors include an adsorbent configurationsuitable for use in a horizontal alignment for input flow perpendicularto the long axis of the reactor, such as parallel plate adsorbents. Thereactor vessels have about a 7.5 to 1 length to width ratio,corresponding to a long axis of about 30 meters and a short axis ofabout 4 meters. The reactors are deployed in a cycle which includes asequence of steps. The first step in the cycle is a feed step at highpressure, such as ˜21 bara (about 2.1 MPaa), for ˜60-120 seconds duringwhich feed gas is supplied to a feed end of a PSA reactor vessel. Anexample of a feed gas is the recycled turbine exhaust gas from a lowemission power generation system. The turbine exhaust gas can bedelivered to the PSA vessel at a temperature of ˜440° C. An example of aturbine exhaust gas composition can be about 11 vol % carbon dioxide,about 84 vol % nitrogen, and a remaining amount of water and other tracespecies. As the fed gas is supplied to a feed end of the vessel, anitrogen product is produced from a product side. The nitrogen productcan have a purity of at least about 90 vol %, a temperature of about440° C., and a pressure of about 20.7 bara (about 2.07 MPaa). After asufficient amount of CO₂ is adsorbed, such as about 85% of the capacityof the adsorbent, a blow down step is started. The blow down step can beperformed for about 30-120 seconds. At the end of the blow down step,the reactor vessel is at a pressure of about 1.3 bara (about 130 kPaa)to about 1.6 bara (about 160 kPaa). The blowdown can be performed eithersolely in the forward direction where only the product end is opened, ora first blowdown in the forward direction can be performed followed by asecond blowdown where both feed and product ends are opened. After theblow down, a low pressure steam purge from the product side can beperformed for about 35-135 seconds to sweep out adsorbed carbon dioxide.The low pressure steam purge generates an output stream containing waterand carbon dioxide. After removal of water, the output stream can have aCO₂ purity of at least about 90 vol %. The output stream can alsocorrespond to at least about 90% (by weight) of the CO₂ present in thefeed to the PSA reactor. Optionally, an additional nitrogen purge can beperformed after the steam purge, in order to sweep out any steam andcarbon dioxide remaining in the reactor. The vessel is thenrepressurized from the feed side to return the PSA reactor vessel to theinitial pressure for performing the separation of the feed gas. Therepressurization can be performed using the feed gas and can typicallytake about 25-60 seconds. The conduct of this PSA cycle can allowseparation of carbon dioxide from nitrogen contained in a turbineexhaust gas, such as a recycled exhaust gas, such that carbon dioxide isrecovered at a rate of at least 90% and with a purity of at least 90 vol% (after condensing out water) while also simultaneously producingnitrogen at greater than 90 vol % purity. The cycle can also use areduced amount of steam, such as from about 0.3 to about 0.6 mol steamper mol of carbon dioxide in the feed gas to the PSA reactor.

EXAMPLE 2 Simulations of Separation of a Turbine Exhaust Gas

The following example is based on simulations of separating CO₂ from N₂in a flue gas or exhaust gas from a turbine for power generation. Thesimulations were based on numerical solution of the transient materialand energy balances involved in a cyclic adsorption/desorption process.The reactor configuration corresponded to the configuration shown inFIG. 2.

Table 1 shows the inputs and results from the simulation. The simulatedflow of exhaust gas was about 820 million SCF/day. The columnscorresponded to various steps in a pressure swing adsorption cycle usinga mixed-metal oxide based adsorbent containing potassium carbonate andlanthanum oxide. The “Feed” and “Steam Purge” columns corresponded toinputs into the process, while the remaining columns corresponded tooutput flows.

TABLE 1 Steam Blow Feed Purge N₂ Product CO₂ product Down P (bara) 211.5 20.7 1.35 1.35 T (° F.) 826 826 837 824 837 MMSCFD 822 81.3 653 15891.4 lb · mol/hr 90200 8930 71800 17400 10000 CO₂ mol % 11 0 0.39 51.55.69 N₂ mol % 84 0 93.3 1.69 89.0 H₂O mol % 5 100 6.33 46.78 5.30

Table 2 shows the inputs and results from another simulation. Thesimulated flow of exhaust gas was about 830 million SCF/day. The columnscorresponded to various steps in a pressure swing adsorption cycle usinga mixed-metal oxide based adsorbent containing potassium carbonate andmagnesium oxide. The “Feed” and “Steam Purge” columns corresponded toinputs into the process, while the remaining columns corresponded tooutput flows.

TABLE 2 Steam Blow Feed Purge N₂ Product CO₂ product Down P (bara) 211.5 20.5 1.37 1.37 T (° F.) 826 826 840 820 840 MMSCFD 834 33.5 708 11643.3 lb · mol/hr 91500 3680 77700 12700 4750 CO₂ mol % 11.0 0 0.72 73.74.21 N₂ mol % 84.0 0 93.4 0.57 90.4 H₂O mol % 5.00 100 5.89 25.8 5.38

Based on the simulations, at least 90% of the CO₂ in the feed wascaptured as part of the desired CO₂ product. In other words, less than10% of the CO₂ in the feed was lost to either the N₂ product or the blowdown stream. As shown in Tables 1 and 2, the purity of the CO₂ productstream was greater than 96%. Note that, since about half of the initialCO₂ product stream was water, after removal of the water, the N₂represented a correspondingly greater percentage of the remaining CO₂product stream.

EXAMPLE 3 Energy Requirements for CO₂ Separation

Use of pressure swing adsorption for separating CO₂ from an exhaust gascan provide advantages in comparison with conventional separationmethods. Table 3 shows a comparison of estimates for total energyconsumed while performing CO₂ separation using pressure swing adsorptionversus two comparative amine separation processes.

TABLE 3 Energy Sorption consumption Pressure P_(final) CO₂ P_(final) N₂(kJ/mol CO₂, Conditions (kPa) (kPa) (kPa) estimated) Low Pressure Amine101 101 101 18.2 (40° C.) High Pressure 1919 101 1919 23.3 Amine (40°C.) Pressure Swing 1919 101 1919 19.1 Adsorption (432° C.)

In Table 3, the low pressure and high pressure amine processes refer toseparation of CO₂ by adsorption in an amine separator. The amineseparation was performed at a temperature of ˜40° C. The sorptionpressure refers to the pressure of the exhaust stream entering theseparation process. The P_(final) CO₂ value was constant and reflectsthe low pressure (such as ambient pressure) nature of the separated CO₂stream. The P_(final) N₂ value corresponds to the pressure of the N₂stream generated by the process after separating out the CO₂. The energyconsumption estimates were based on thermodynamic calculations for thevarious processes at the conditions indicated.

In Table 3, the energy required for CO₂ separation by pressure swingadsorption was lower than the energy required for high pressure aminetreatment, and was comparable to the energy required for the lowpressure amine treatment. However, as shown in Table 3, using pressureswing adsorption for CO₂ separation provided several advantages withregard to the properties of the N₂ stream generated during separation.First, the temperature of the N₂ product stream was roughly maintainedduring a pressure swing adsorption process, while the amine separationprocesses required a reduction in temperature, such as to ˜40° C. Inorder to use the N₂ product stream for additional power generation, thetemperature of the N₂ product streams from the amine processes wouldtypically need to be raised back at least to about 300-400° C. orgreater, which would require additional energy cost not included in theseparation energy estimate shown in Table 3. The additional energy costto return the N₂ product stream to a higher temperature can be mitigatedby use of heat exchangers, so that then energy of the exhaust prior toseparation could be transferred to the N₂ product stream afterseparation. However, this would require additional substantial equipmentfootprint, and therefore would be less desirable.

Another advantage of the pressure swing adsorption separation withrespect to the low pressure amine separation can include the maintenanceof the pressure of the N₂ product stream during the separation, whichcan allow the N₂ product stream to be used for other purposes, such aspower generation, without having to expend energy to modify the stream.

EXAMPLE 4 Simulation of CO₂ Purity and Recovery for EOR Applications

Using a configuration corresponding to FIG. 1 and conditions disclosedherein, a purified CO₂ gas stream (flue gas), e.g., from line 150 canhave a pressure of about 21 bara (˜2.1 MPa). FIG. 3 shows CO₂ recoveryrates and CO₂ purity for a flue gas having this pressure. In situationswhere a higher gas pressure is desired, an additional compressor can beadded between the outlet of exhaust gas recycle turbine and the PSAvessel.

FIG. 3 depicts integrated unit performance using a combination ofnumerical simulations and experimental data on key sorbent properties.Simulations were conducted based on a flue gas input to the PSA unitcontaining ˜11 vol % CO₂, ˜84 vol % N₂, ˜5 vol % water at a temperatureof at least 400° C., using a suitable high temperature adsorbent (e.g.,a mixed-metal oxide and/or a hydrotalcite such as disclosed herein) withnominal flow of ˜820 million SCFD (standard cubic feet per day). Thesimulations used herein relied on numerical solutions of the materialand energy balances involved in adsorption and desorption process stepsof the PSA cycle. The saturation CO₂ capacity for a sorbent wasdetermined using standard thermogravimetric (TGA) and breakthroughcolumn measurements.

FIG. 3 shows the trade-off between CO₂ purity versus steam use for theULET power plant with ˜21 bara emission gas pressure. The numbers shownat each data point of CO₂ purity are meant to correspond to the CO₂recovery rate. FIG. 3 also shows a comparison between CO₂ purity, CO₂capture rate, plant foot print, and steam usage.

All further uses of purified CO₂, e.g., enhanced hydrocarbon recovery,such as down-hole EOR, can typically require subsequent downstreamcompression to the required reservoir injection pressure or to the localCO₂ pipeline pressure (e.g., ˜2215 psig, or ˜150 bara). This pressure isspecified for the US CO₂ pipeline network. The actual pressure requiredis a function of the reservoir and oil properties and could be much lessthan 2215 psig.

In order to reduce the downstream compression costs, one approach can beto regenerate CO₂ at elevated pressure (e.g., at ˜2-3 bara). FIG. 3shows that a 4-bed PSA process can deliver relatively high purity CO₂(about 97% to about 99%) at a CO₂ capture rate while also maintainingrelatively low steam usage (as measured by the ratio of moles of steamapplied to moles of CO₂ generated, preferably not more than 1.0) at arelatively higher CO₂ pressure (again, ˜2-3 bara or higher). It shouldbe noted that the first stage of compression has the largest equipmentfootprint and thus the largest economic penalty, because of the verylarge volume of low pressure gas processed. Therefore, removing earlierstages of compression yields a much higher economic benefit thanreducing the ultimate compression value (i.e., removing later stages ofcompression). Ultimate total compression for down-hole EOR applicationscan be above 100 bara, e.g., from about 100 bara to about 250 bara.

The benefits of the current invention, as evidenced by this Example, canbe 2-fold—[1] there can be an overall reduction in equipment of (piping)accompanying reduced volumes of gas, which can be enabled by theelevated exhaust pressure; and [2] there can be a reduced compressionpower requirement resulting from eliminating the first (or more) stagesof compression. The combined effect of the benefits can include a majorfootprint and energy advantage, which can be important for integratingpower plants with enhanced hydrocarbon recovery facilities, particularlyfor conventional EOR.

In the case of lowered purity requirements (which may be suitable forcertain reservoirs), the high temperature PSA can be operated withoutthe use of an intentionally added steam purge. For example, a 3-bed hightemperature PSA configuration operating at ˜21 bar without steam canadvantageously produce CO₂ at ˜60% or higher both purity and recovery.Additionally or alternately, a 3 bed high temperature PSA configurationoperating at ˜55 bar can advantageously produce CO₂ at ˜70% or higherpurity, in the absence of intentionally added steam. Indeed, removingsteam entirely can result in a significant reduction in processcomplexity, since various steam condensation, heat exchange, andcorrosion related equipment can advantageously be eliminated in thatscenario.

Furthermore, lower purity CO₂ may be suitable, or even desirable, forcertain recovery operations, such as unconventional reservoirs,including those related to shale gas and rock formations, e.g., sinceincreasing non-CO₂ “impurities” can lower the viscosity of the mixtureto be injected into the reservoir, which can, in certain circumstances,allow improved absorption and/or subsequent improved hydrocarbonproduction. For instance, in a nominal reservoir at ˜2000 psig and ˜100°F., an 80/20 CO₂/N₂ gas stream can have a viscosity of ˜0.03 cPs, whilea 70/30 CO₂/N₂ gas stream can have a viscosity of ˜0.025 cPs. Increasedflexibility in varying CO₂ purity can, in certain circumstances, allowthe methods and apparati according to the invention to have an increasedproduction efficiency and/or to achieve an overall production of adeposit/reservoir not easily attainable without such flexibility.

For example, in the use of CO₂ for enhanced natural gas recovery fromshale gas, the CO₂ purity in the recovery input stream may need toincrease over time (continuously, stepwise, intermittently, gradually,or even dramatically) as more CH₄ gets produced, and there can be agreater need for CO₂ to displace CH₄, e.g., adsorbed on the organicmatter in the reservoir rock. Therefore, the amount and/or purity of CO₂required for injection can increase over time, as the content of CH₄ inthe reservoir becomes reduced through continued production. This canresult in a greater demand for CO₂ over time, in terms of larger volumesand/or in terms of purity, using the integrated methods according to theinvention. In turn, in certain embodiments, this can require a highersteam usage in the PSA process, which variable steam demand can beenabled by the real-time adjustment capability described herein.

EXAMPLE 5 Performing PSA on a Portion of Recycled Exhaust for HighPurity CO₂

The following prophetic example is based on a configuration for apressure swing adsorption reactor similar to the configuration shown inFIG. 2. In this example, a mixed-metal oxide based adsorbent is used ina plurality of PSA reactors to separate CO₂ and N₂. The separation isperformed at a temperature of about 440° C. The PSA reactors cancorrespond to ˜3 horizontally aligned vessels. The reactors can includean adsorbent configuration suitable for use in a horizontal alignmentfor input flow perpendicular to the long axis of the reactor, such asparallel plate adsorbents and/or adsorbent bed(s). The reactor vesselscan have a long axis of about 30 m and a short axis of about 4 m. Thereactors can be deployed in a cycle including a sequence of steps. Thefirst step in the cycle is a feed step at relatively high pressure, suchas ˜21 bara (˜2.1 MPa), for about 150 seconds during which feed gas issupplied to a feed end of a PSA reactor vessel. An example of a feed gascan include or be the recycled turbine exhaust gas from a low emissionpower generation system. The turbine exhaust gas can be delivered to thePSA vessel at a temperature of about 440° C. An example of a turbineexhaust gas composition can be ˜11 vol % CO₂, ˜84 vol % N₂, and aremaining amount of water and other trace species. As the feed gas issupplied to a feed end of the vessel, a nitrogen product can be producedfrom a product side. The nitrogen product can have a purity of at leastabout 90 vol %, a temperature of about 440° C., and a pressure of about20.7 bara (˜2.07 MPa). After a sufficient amount of CO₂ is adsorbed,such as about 85% of the capacity of the adsorbent, a blow down step canbe started. The blow down step is performed for ˜40 seconds in theforward (flow) direction. At the end of the blow down step, the reactorvessel can be at a pressure of about 1.5 bara (˜150 kPa). The blowdowncan be performed either solely in the forward (flow) direction whereonly the product end is opened, or a first blowdown in the forward(flow) direction can be performed, followed by a second blowdown whereboth feed and product ends are opened. Other combinations of thesesequences of blowdown are additionally or alternately possible. Afterthe blowdown, a relatively low pressure steam purge (about 1-1.5 bara,˜100-150 kPa) from the product side can be performed for about 205seconds to sweep out adsorbed carbon dioxide. The relatively lowpressure steam purge can generate an output stream containing water andcarbon dioxide at a pressure of about 1.48 bara (˜148 kPa). Afterremoval of water by condensation, the output stream can have a CO₂purity of at least about 99 mol %. The output stream can also correspondto at least about 82% of the CO₂ present in the feed to the PSA reactor.Optionally, an additional nitrogen purge can be performed after thesteam purge, in order to sweep out any steam and carbon dioxideremaining in the reactor. The vessel can then be re-pressurized from thefeed side to return the PSA reactor vessel to the initial pressure of˜21 bara (˜2.1 MPa) for performing the separation of the feed gas. There-pressurization can be performed using product gas for ˜55 seconds.The conduct of this PSA cycle can allow separation of carbon dioxidefrom nitrogen contained in a turbine exhaust gas, such as a recycledexhaust gas, such that carbon dioxide can be recovered at a rate of atleast 80% and with a purity of at least 99% (after condensing outwater). The cycle can also use a reduced amount of steam, such as about0.59 mol steam per mol of carbon dioxide recovered as product.

EXAMPLE 6 Performing PSA on a Portion of Recycled Exhaust for HighPurity CO₂

The following prophetic example is based on a configuration for apressure swing adsorption reactor similar to the configuration shown inFIG. 2. In this example, a mixed-metal oxide based adsorbent is used ina plurality of PSA reactors to separate CO₂ and N₂. The separation isperformed at a temperature of about 440° C. The PSA reactors cancorrespond to ˜4 horizontally aligned vessels. The reactors can includean adsorbent configuration suitable for use in a horizontal alignmentfor input flow perpendicular to the long axis of the reactor, such asparallel plate adsorbents and/or adsorbent bed(s). The reactor vesselscan have a long axis of about 35 m and a short axis of about 4 m. Thereactors can be deployed in a cycle including a sequence of steps. Thefirst step in the cycle is a feed step at relatively high pressure, suchas ˜21 bara (˜2.1 MPa), for about 200 seconds during which feed gas issupplied to a feed end of a PSA reactor vessel. An example of a feed gascan include or be the recycled turbine exhaust gas from a low emissionpower generation system. The turbine exhaust gas can be delivered to thePSA vessel at a temperature of about 440° C. An example of a turbineexhaust gas composition can be ˜11 vol % CO₂, ˜84 vol % N₂, and aremaining amount of water and other trace species. As the feed gas issupplied to a feed end of the vessel, a nitrogen product can be producedfrom a product side. The nitrogen product can have a purity of at leastabout 90 vol %, a temperature of about 440° C., and a pressure of about20.7 bara (˜2.07 MPa). After the feed step, a blow down step can beperformed for ˜35 seconds in the forward (flow) direction. After theblowdown, a relatively low pressure steam purge (about 1-1.5 bara,˜100-150 kPa) from the product side can be performed for about 530seconds to sweep out adsorbed carbon dioxide. The relatively lowpressure steam purge can generate an output stream containing water andcarbon dioxide at a pressure of about 1.85 bara (˜185 kPa). Afterremoval of water by condensation, the output stream can have a CO₂purity of at least about 99 mol %. The output stream can also correspondto at least about 72% of the CO₂ present in the feed to the PSA reactor.The vessel can then be re-pressurized from the feed side to return thePSA reactor vessel to the initial pressure of ˜21 bara (˜2.1 MPa) forperforming the separation of the feed gas. The re-pressurization can beperformed using product gas for ˜35 seconds. The conduct of this PSAcycle can allow separation of carbon dioxide from nitrogen contained ina turbine exhaust gas, such as a recycled exhaust gas, such that carbondioxide can be recovered at a rate of at least 70% and with a purity ofat least 99% (after condensing out water). The cycle can also use areduced amount of steam, such as about 0.77 mol steam per mol of carbondioxide recovered as product.

EXAMPLE 7 Performing PSA on a Portion of Recycled Exhaust for HighPurity CO₂

The following prophetic example is based on a configuration for apressure swing adsorption reactor similar to the configuration shown inFIG. 2. In this example, a mixed-metal oxide based adsorbent is used ina plurality of PSA reactors to separate CO₂ and N₂. The separation isperformed at a temperature of about 440° C. The PSA reactors cancorrespond to ˜4 horizontally aligned vessels. The reactors can includean adsorbent configuration suitable for use in a horizontal alignmentfor input flow perpendicular to the long axis of the reactor, such asparallel plate adsorbents. The reactor vessels can have a long axis ofabout 35 m and a short axis of about 4 m. The reactors can be deployedin a cycle including a sequence of steps. The first step in the cycle isa feed step at relatively high pressure, such as ˜21 bara (˜2.1 MPa),for about 200 seconds during which feed gas is supplied to a feed end ofa PSA reactor vessel. An example of a feed gas can include or be therecycled turbine exhaust gas from a low emission power generationsystem. The turbine exhaust gas can be delivered to the PSA vessel at atemperature of about 440° C. An example of a turbine exhaust gascomposition can be ˜11 vol % CO₂, ˜84 vol % N₂, and a remaining amountof water and other trace species. As the feed gas is supplied to a feedend of the vessel, a nitrogen product can be produced from a productside. The nitrogen product can have a purity of at least about 90 vol %,a temperature of about 440° C., and a pressure of about 20.7 bara (˜2.07MPa). After the feed step, a blow down step can be performed for ˜35seconds in the forward (flow) direction. After the blowdown, arelatively low pressure steam purge (about 1-1.5 bara, ˜100-150 kPa)from the product side can be performed for about 530 seconds to sweepout adsorbed carbon dioxide. The relatively low pressure steam purge cangenerate an output stream containing water and carbon dioxide at apressure of about 2.85 bara (˜285 kPa). After removal of water bycondensation, the output stream can have a CO₂ purity of at least about97 mol %. The output stream can also correspond to at least about 65% ofthe CO₂ present in the feed to the PSA reactor. The vessel can then bere-pressurized from the feed side to return the PSA reactor vessel tothe initial pressure of ˜21 bara (˜2.1 MPa) for performing theseparation of the feed gas. The re-pressurization can be performed usingproduct gas for ˜35 seconds. The conduct of this PSA cycle can allowseparation of carbon dioxide from nitrogen contained in a turbineexhaust gas, such as a recycled exhaust gas, such that carbon dioxidecan be recovered at a rate of at least 60% and with a purity of at least97% (after condensing out water). The cycle can also use a reducedamount of steam, such as about 0.65 mol steam per mol of carbon dioxiderecovered as product.

EXAMPLE 8 Performing PSA on a Portion of Recycled Exhaust

The following prophetic example is based on a configuration for apressure swing adsorption reactor similar to the configuration shown inFIG. 2. In this example, a mixed-metal oxide based adsorbent is used ina plurality of PSA reactors to separate CO₂ and N₂. The separation isperformed at a temperature of about 440° C. The PSA reactors cancorrespond to ˜3 horizontally aligned vessels. The reactors can includean adsorbent configuration suitable for use in a horizontal alignmentfor input flow perpendicular to the long axis of the reactor, such asparallel plate adsorbents and/or adsorbent bed(s). The reactor vesselscan have a long axis of about 30 m and a short axis of about 4 m. Thereactors can be deployed in a cycle including a sequence of steps. Thefirst step in the cycle is a feed step at relatively high pressure, suchas ˜21 bara (˜2.1 MPa), for about 110 seconds during which feed gas issupplied to a feed end of a PSA reactor vessel. An example of a feed gascan include or be the recycled turbine exhaust gas from a low emissionpower generation system. The turbine exhaust gas can be delivered to thePSA vessel at a temperature of about 440° C. An example of a turbineexhaust gas composition can be ˜11 vol % CO₂, ˜84 vol % N₂, and aremaining amount of water and other trace species. As the feed gas issupplied to a feed end of the vessel, a nitrogen product can be producedfrom a product side. The nitrogen product can have a purity of at leastabout 90 vol %, a temperature of about 440° C., and a pressure of about20.7 bara (˜2.07 MPa). After the feed step, blowdown steps can beperformed for ˜5 seconds in the reverse (counter-flow) direction,followed by ˜25 seconds in the forward (flow) direction. After theblowdown steps, a relatively low pressure steam purge (about 1-1.5 bara,˜100-150 kPa) from the product side can be performed for about 173seconds to sweep out adsorbed carbon dioxide. The relatively lowpressure steam purge can generate an output stream containing water andcarbon dioxide at a pressure of about 1.35 bara (-135 kPa). Afterremoval of water by condensation, the output stream can have a CO₂purity of at least about 63 mol %. The output stream can also correspondto at least about 69% of the CO₂ present in the feed to the PSA reactor.The vessel can then be re-pressurized from the feed side to return thePSA reactor vessel to the initial pressure of ˜21 bara (˜2.1 MPa) forperforming the separation of the feed gas. The re-pressurization can beperformed using product gas for ˜17 seconds. The conduct of this PSAcycle can allow separation of carbon dioxide from nitrogen contained ina turbine exhaust gas, such as a recycled exhaust gas, such that carbondioxide can be recovered at a rate of at least 65% and with a purity ofat least 60% (after condensing out water).

EXAMPLE 9 Performing PSA on a Portion of Recycled Exhaust

FIG. 3 shows how the recovery (represented as a molar ratio) and purity(represented as a percent) trade off against steam usage for exemplaryPSA configurations that can further illustrate the invention. For eachof the cases shown, the feed composition and pressure are similar tothose described in the examples above. In FIG. 3, either ˜3-vessel or˜4-vessel PSA configurations are illustrated for typical adsorbentproperties of mass transfer and adsorbent capacity. As seen in FIG. 3,higher purity CO₂ (>95 vol %) can be achievable with increased steamusage, but still less than ˜1.0 mol/mol of CO₂ recovered. In addition,the use of ˜4 PSA vessels can allow a reduced pressure swing via the useof a higher relative purge pressure (>about 1.35-1.5 bara, typicallyfrom ˜2 bara to ˜3 bara), which can reduce both equipment and energyrequirements for subsequent CO₂ compression prior to use in EORfacilities. Further improvement of the ˜4-vessel recoveries shown inFIG. 3 can be obtained using configurations where the vessels are influid communication with each other.

EXAMPLE 10 3-Vessel PSA Configuration Using a Portion of RecycledExhaust

FIG. 4 shows a 3-vessel configuration that is illustrative but notlimiting of one possible arrangement of adsorber vessels within thescope of the invention. In this configuration, one vessel is on feed andhence making nitrogen product at all times. The other two vessels can beundergoing other steps of the cycle, e.g., that regenerate theadsorbent, whilst the first vessel is making product at relatively highpressure. In this particular 3-vessel arrangement, there is no fluidconnection (i.e., exchange of gas streams) between the vessels, whichreduces cycle complexity as well as equipment such as interconnectingpiping and valving.

EXAMPLE 11 4-Vessel PSA Configuration Using a Portion of RecycledExhaust

FIGS. 5-6 show 4-vessel configurations that are illustrative but notlimiting of another possible arrangement of adsorber vessels within thescope of the invention. In the configurations of FIGS. 5-6, at least onevessel is on feed at all times. Two or three of the other vessels can beundergoing other steps of the cycle, e.g., that regenerate theadsorbent, whilst the at least one vessel is making product atrelatively high pressure. In the particular 4-vessel arrangement of FIG.5, there is no fluid connection (i.e., exchange of gas streams) betweenthe vessels, which reduces cycle complexity as well as equipment such asinterconnecting piping and valving. However 4-vessel arrangements permitcycles to be conducted whereby two of the vessels not on feed canexchange gas, e.g., by employing a pressure equalization step whereby afirst vessel at relatively higher pressure can be depressurized into asecond vessel at relatively lower pressure, thereby increasing thepressure of the second vessel and decreasing the pressure of the firstvessel, such as shown in FIG. 6. This type of cycle can permit higher(CO₂) recovery, since the stream(s) containing the target gas (CO₂)is(are) not released to the ambient atmosphere, but is(are) sent toanother adsorbent vessel. The advantages of higher recovery from using a4-vessel configurations (or configurations using more than 4 vessels)can be offset to some extent by the increased cost of added vessels,interconnecting piping and valving, and associated cycle controlequipment required.

EXAMPLE 12 Dual Integrated PSA System for Integrated Emissions Controland Hydrocarbon Production

FIG. 7 shows an application of a pressure swing absorption processdescribed above. The application may be a system that includes a powerplant (not shown) which produces flue gas at a relatively high pressureand temperature. The flue gas of this example is a mix of primarily CO₂and N₂. In addition to the power generating plant (e.g., powergeneration system 100 in FIG. 1), the system may include two PSAs and ahydrocarbon producing reservoir, where an injection well and aproduction well may be drilled near one another. The production well maybe drilled in a hydrocarbon pay-zone in order to extract thehydrocarbons present in the reservoir. The injection well may be drilledin the vicinity of the production well in order to affect, e.g.,pressure in the reservoir, or the content and the properties of theproduced hydrocarbons, and, thereby, enhance the production.

Out of the two PSAs in the system, at least PSA-1 may be the pressureswing adsorber 210 shown in FIG. 2, which is able to adequately processthe flue gas from the power plant arriving at a relatively high pressureand temperature. PSA-2, on the other hand, may be fed with a mix ofgasses flowing from the production well, and, therefore, may not requirethe pressure and temperature capabilities of the pressure swing adsorber210, for example. Thus, a conventional adsorber may be deemed suitableto be used as PSA-2, depending on the thermodynamic properties of thegas departing the production well.

The integrated emission control may begin by feeding the flue gas fromthe power plant into PSA-1. As shown, any gasses additional to CO₂ andN₂ will be omitted from the discussion and an approximation will be madethat the flue gas consists of CO₂ and N₂ only.

In one embodiment, the flue gas from the power plant may be processed tobe utilized in extracting hydrocarbons from an oil/gas rich formation.However, while the properties of N₂ allow for its usage mainly as apressurizing agent, CO₂, on the other hand, can be particularlyeffective in driving the hydrocarbons out of the reservoir by mixingwith them. In other words, CO₂ may be used to change composition andflow parameters of the produced oil/gas in order to facilitate theproduction, without affecting the chemical properties of the oil/gas. Inorder to optimize the introduction of CO₂, the composition of CO₂ needsto be controlled, and the typical apportion of N₂ in the flue gas mayrender the mix of the flue gas unusable for such a purpose. Hence, CO₂may need to be separated from N₂ to prepare it for injection in thehydrocarbon reservoir.

As illustrated in FIG. 7, the separation of CO₂ and N₂ may be performedby PSA-1. The flue gas may enter PSA-1 at ˜20bara, where CO₂ may beadsorbed and N₂ may be recovered and stored to be used for a variety ofindustrial applications (or, as will be discussed in reference to FIG.8, N₂ may be recycled back into the system). PSA-1 may be placed betweenthe power plant and an injection well that may intake CO₂ adsorbed byPSA-1. The injection well may be drilled near a hydrocarbon reservoir inorder to modify the properties of the reservoir and optimize recovery ofhydrocarbons. Of note, CO₂ required by the injection well may be afunction of the composition of the hydrocarbons to be extracted.Accordingly, an ability of PSA-1 to adjust its adsorption cycle mayprovide a significant benefit. Namely, in addition to merely providingCO₂ by removing N₂, PSA-1 may also optimize the composition of CO₂flowing from the power plant to be suitable to the requirements of aparticular reservoir. For example, as the reservoir ages, it may requirelevels of injected CO₂ to vary with the aging process, which may beaccomplished by setting the adsorption cycle to be suitable for anystage of the life of the reservoir.

Once the CO₂ is removed from PSA-1, it may mix with CH₄ that is presentin the air above the injection well and a tuned composition of CO₂/CH₄may be formed to be injected. Further, the injection well may be incommunication with the production well and the injection of the CO₂/CH₄composition may affect the extraction of oil/gas from the reservoir. Theproduced hydrocarbons may have a liquid and a gaseous phase. Consideringthat CO₂ may be introduced to mix with the hydrocarbons to facilitatethe flow, the gaseous phase may be a CO₂/CH₄ mixture. Thus, a separationof CO₂ and CH₄ may be necessary in order to purify CH₄ as one of the endproducts of the system.

The natural gas purification may occur in PSA-2. As mentioned above, ininstances where the produced CO₂/CH₄ mixture is at a pressuresubstantially lower than the pressure of flue gas exiting the powerplant (˜20bara), a conventional adsorber may be used as PSA-2. Dependingon the temperature of the produced CO₂/CH₄ mixture, PSA-2 may be a hotPSA. PSA-2 may adsorb CO₂ from the mixture and permit flow of purifiedCH₄ as the light component of PSA-2. Depending on the properties of thegas entering PSA-2 from the production well, the gas exiting PSA-2 maybe used back in the system as a purging agent in PSA-1. In addition, acomponent of the gas entering PSA-2 from the production well may flowthrough and purge PSA-2 to the injection well.

EXAMPLE 13 Dual Integrated PSA System with N₂ Purge of at Least One PSA

FIG. 8 shows an example where N₂ may be redirected to be used back inthe dual integrated PSA system. As mentioned, when the flue gas isintroduced in PSA-1 at, for example, ˜20bara, the pressure of N₂ exitingthe adsorber may remain relatively high (˜19bara). As a result, in thisexample N₂ is used as a pressurizing agent to purge PSA-2, and/or, tofurther increase the pressure of the hydrocarbons in the zone ofinterest of the reservoir in order to push them out of the rock. This ispossible because N₂ is an inert gas that is unlikely to affect thechemical content of the hydrocarbons in the formation.

Although the present invention has been described in terms of specificembodiments, it need not necessarily be so limited. Suitablealterations/modifications for operation under specific conditions shouldbe apparent to those skilled in the art. It is therefore intended thatthe following claims be interpreted as covering all suchalterations/modifications as fall within the true spirit/scope of theinvention.

1. A method for optimizing hydrocarbon production, comprising: passingrecycle exhaust gas from a power generation plant to a first swingadsorption reactor, wherein the exhaust gas includes CO₂ and N₂;adsorbing the CO₂ from the exhaust gas on a first adsorbent material ofthe first swing adsorption reactor, wherein an adsorption cycle of thefirst swing adsorption reactor is variable; injecting the CO₂ adsorbedby the first swing adsorption reactor in a hydrocarbon reservoir byusing an injection well; producing a mixture of hydrocarbons and CO₂ byusing a production well, which is in communication with the injectionwell; and purifying the produced hydrocarbons by adsorbing the producedCO₂ from the production well on a second adsorbent material of a secondswing adsorption reactor.
 2. The method of claim 1, wherein a N₂ streamunadsorbed by the first swing adsorption reactor exits the first swingadsorption reactor at a pressure that is substantially the same as apressure of the exhaust gas from the power generation plant.
 3. Themethod of claim 1, further comprising: recovering a N₂ stream unadsorbedby the first swing adsorption reactor.
 4. The method of claim 1, furthercomprising: purging the second swing adsorption reactor with a stream ofN₂ unadsorbed by the first swing adsorption reactor.
 5. The method ofclaim 1, further comprising: feeding the purified hydrocarbons back intothe power generation plant and generating power.
 6. The method of claim1, further comprising: wherein the adsorption cycle of the first swingadsorption reactor is varied to adjust composition of adsorbed CO₂ basedon a composition of hydrocarbons in the hydrocarbon reservoir.
 7. Themethod of claim 6, wherein the composition of the hydrocarbons in thehydrocarbon reservoir varies with age of the reservoir.
 8. The method ofclaim 1, wherein at least one of the first swing adsorption reactor andthe second swing adsorption reactor is a high-temperature reactor. 9.The method of claim 1, wherein the hydrocarbons include CH₄.
 10. Themethod of claim 1, further comprising: purging the first swingadsorption reactor with at least one of steam, a stream of N₂, a streamof CO₂, and a stream of CH₄.
 11. The method of claim 1, furthercomprising: purging the second swing adsorption reactor with at leastone of a stream of CO₂ and a stream of CH₄ flowing from the productionwell.
 12. A method for optimizing power generation, comprising: passingrecycle exhaust gas from a power generation plant to a first swingadsorption reactor, wherein the exhaust gas includes CO₂ and N₂;adsorbing the CO₂ from the exhaust gas on a first adsorbent material ofthe first swing adsorption reactor, wherein an adsorption cycle of thefirst swing adsorption reactor is variable; injecting the CO₂ adsorbedby the first swing adsorption reactor in a hydrocarbon reservoir byusing an injection well; producing a mixture of hydrocarbons and CO₂ byusing a production well, which is in communication with the injectionwell; and purifying the produced hydrocarbons by adsorbing the producedCO₂ from the production well on a second adsorbent material of a secondswing adsorption reactor.
 13. The method of claim 12, wherein a N₂stream unadsorbed by the first swing adsorption reactor exits the firstswing adsorption reactor at a pressure that is substantially the same asa pressure of the exhaust gas from the power generation plant.
 14. Themethod of claim 12, further comprising: recovering a N₂ streamunadsorbed by the first swing adsorption reactor.
 15. The method ofclaim 12, further comprising: purging the second swing adsorptionreactor with a stream of N₂ unadsorbed by the first swing adsorptionreactor.
 16. The method of claim 12, further comprising: feeding thepurified hydrocarbons back into the power generation plant andgenerating power.
 17. The method of claim 12, further comprising:wherein the adsorption cycle of the first swing adsorption reactor isvaried to adjust composition of adsorbed CO₂ based on a composition ofhydrocarbons in the hydrocarbon reservoir.
 18. The method of claim 17,wherein the composition of the hydrocarbons in the hydrocarbon reservoirvaries with age of the reservoir.
 19. The method of claim 12, wherein atleast one of the first swing adsorption reactor and the second swingadsorption reactor is a high-temperature reactor.
 20. The method ofclaim 12, wherein the hydrocarbons include CH₄.
 21. The method of claim12, further comprising: purging the first swing adsorption reactor withat least one of steam, a stream of N₂, a stream of CO₂, and a stream ofCH₄.
 22. The method of claim 12, further comprising: purging the secondswing adsorption reactor with at least one of a stream of CO₂ and astream of CH₄ flowing from the production well.
 23. A system foroptimizing hydrocarbon production, comprising: a power generation plantthat produces recycle exhaust gas, wherein the exhaust gas includes CO₂and N₂; a first swing adsorption reactor, wherein the power generationplant passes the exhaust gas to the first swing adsorption reactor,wherein the first swing adsorption reactor adsorbs the CO₂ from theexhaust gas on a first adsorbent material of the first swing adsorptionreactor, and wherein an adsorption cycle of the first swing adsorptionreactor is variable; an injection well that injects the CO₂ adsorbed bythe first swing adsorption reactor in a hydrocarbon reservoir; aproduction well that is in communication with the injection well andthat produces a mixture of hydrocarbons and CO₂; and a second swingadsorption reactor that purifies the produced hydrocarbons by adsorbingthe produced CO₂ from the production well on a second adsorbent materialof the second swing adsorption reactor.
 24. The system of claim 23,wherein the adsorption cycle of the first swing adsorption reactor isvaried to adjust composition of adsorbed CO₂ based on a composition ofhydrocarbons in the hydrocarbon reservoir.
 25. The system of claim 23,wherein the purified hydrocarbons are fed back into the power generationplant to generate power.
 26. A system for optimizing power generation,comprising: a power generation plant that produces recycle exhaust gas,wherein the exhaust gas includes CO₂ and N₂; a first swing adsorptionreactor, wherein the power generation plant passes the exhaust gas tothe first swing adsorption reactor, wherein the first swing adsorptionreactor adsorbs the CO₂ from the exhaust gas on a first adsorbentmaterial of the first swing adsorption reactor, and wherein anadsorption cycle of the first swing adsorption reactor is variable; aninjection well that injects the CO₂ adsorbed by the first swingadsorption reactor in a hydrocarbon reservoir; a production well that isin communication with the injection well and that produces a mixture ofhydrocarbons and CO₂; and a second swing adsorption reactor thatpurifies the produced hydrocarbons by adsorbing the produced CO₂ fromthe production well on a second adsorbent material of the second swingadsorption reactor.
 27. The system of claim 26, wherein the adsorptioncycle of the first swing adsorption reactor is varied to adjustcomposition of adsorbed CO₂ based on a composition of hydrocarbons inthe hydrocarbon reservoir.
 28. The system of claim 26, wherein thepurified hydrocarbons are fed back into the power generation plant togenerate power.